Reversible heat exchangers in compressed air energy storage systems

ABSTRACT

A method of processing a stream of compressed air travelling between a gas compressor/expander subsystem and an underground accumulator in a compressed air energy storage system may include directing a thermal storage liquid through the first liquid flow path in a liquid charging flow direction from a thermal source reservoir toward a thermal storage reservoir whereby at least a portion of the thermal energy in the compressed air is transferred from the compressed air into the thermal storage liquid within the first reversible heat exchanger; including redirecting the compressed air through the first gas flow path in a gas discharging flow direction that is opposite the gas charging flow direction and redirecting the thermal storage liquid through the first liquid flow path in a liquid discharging flow direction whereby at least a portion of the thermal energy in the thermal storage liquid is returned into the compressed air.

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to U.S. Provisional Pat. Application Serial No. 62/802,746, filed Feb. 8, 2019 and entitled A Compressed Gas Energy Storage System, the entirety of this application being incorporated by reference herein.

FIELD

The present disclosure relates generally to compressed gas energy storage, and more particularly to a compressed gas energy storage system such as, for example, one including a hydrostatically compensated, compressed air energy storage accumulator located underground, the use thereof.

INTRODUCTION

Electricity storage is highly sought after, in view of the cost disparities incurred when consuming electrical energy from a power grid during peak usage periods, as compared to low usage periods. The addition of renewable energy sources, being inherently of a discontinuous or intermittent supply nature, increases the demand for affordable electrical energy storage worldwide.

Thus there exists a need for effectively storing the electrical energy produced at a power grid or a renewable source during a non-peak period and providing it to the grid upon demand. Additionally, to the extent that the infrastructural preparation costs and the environmental impact from implementing such infrastructure are minimized, the utility and desirability of a given solution is enhanced.

Furthermore, as grids transform and operators look to storage in addition to renewables to provide power and replace traditional forms of generation that also provide grid stability, such as voltage support, a storage method that offers inertia based synchronous storage is highly desirable.

SUMMARY OF THE INVENTION

This summary is intended to introduce the reader to the more detailed description that follows and not to limit or define any claimed or as yet unclaimed invention. One or more inventions may reside in any combination or sub-combination of the elements or process steps disclosed in any part of this document including its claims and figures.

The present invention is a novel system and method for repurposing an excavation shaft used to construct a compressed gas energy storage system for use as a thermal storage reservoir. The invention contemplates two states of the system: first, when the system is being constructed; and second, when the system is in operation as a compressed gas energy storage system. In the construction state, the excavation shaft is connected to an accumulator and configured so that the interior of the accumulator is accessible via the excavation shaft. In the operation state, the excavation shaft remains connected to the accumulator, but with a seal on the lower end of the excavation shaft, used to store thermal storage media that exchanges thermal energy with the compressed gas.

In a preferred embodiment, the excavation shaft is lined with a shaft liner to make the shaft substantially liquid impermeable and reduce transfer of thermal energy with the surrounding ground.

The invention contemplates a variety of possible designs of the excavation shaft, which may maintain its original shape as excavated, or may be further developed with at least one chamber attached to the excavation shaft to aid in storing the thermal storage media.

There are several possibilities for the thermal storage media, including liquids or solids, such as granular particles like sand or gravel. Similarly, there are many possible configurations for the heat exchange of thermal energy with the compressed gas, including both direct and indirect heat exchanger. The choice of heat exchanger may be influenced by the choice of thermal storage media.

Water may be a preferable choice of thermal storage media. Water has relatively fewer environmental concerns than some other possible thermal storage fluids, has relatively few or limited adverse effects on human health, is relatively plentiful and inexpensive and can be used at suitable operating temperatures for the systems described herein. If water is pressurized above its vapour pressure for a given temperature, then the water will stay in its liquid state even if it would have boiled were it being maintained at a lower pressure. Pressuring water to above atmospheric pressures may help keep it in its liquid state at temperatures higher than 100 deg. C, which may help facilitate the storage of more thermal energy within the water than would be possible at atmospheric pressure.

In accordance with one broad aspect of the teachings described herein, which may be used alone or in combination with any other aspect, a compressed gas energy storage system may include an accumulator disposed underground and having an interior configured to contain compressed gas when in use; a gas compressor/expander subsystem spaced apart from the accumulator and comprising at least a first compression stage having a gas inlet and a gas outlet in fluid communication with the accumulator interior via a gas flow path for conveying compressed gas to the accumulator when in a charging mode and from the accumulator when in a discharging mode; at least a first thermal storage reservoir disposed at least partially underground and comprising; i. an excavation shaft extending between an upper end accessible from the surface and a lower end connected to the accumulator and configured so that when the accumulator was being constructed the interior of the accumulator was accessible via the excavation shaft, ii. a lower end wall sealing the lower end of the excavation shaft and fluidly isolating the excavation shaft from the interior of the accumulator, iii. an upper end wall sealing the upper end of the excavation shaft and fluidly isolating the excavation shaft from the atmosphere, iv. a thermal storage media disposed within the excavation shaft and configured to exchange thermal energy with the compressed gas travelling through the gas flow path; whereby when the compressed gas energy storage system is in the charging mode thermal energy is transferred from the compressed gas stream being conveyed into the accumulator to the thermal storage media, and when the compressed gas energy system is in the discharging mode thermal energy is transferred from the thermal storage media to the compressed gas stream being conveyed from the accumulator.

In accordance with another broad aspect of the teachings described herein, a method of processing a stream of compressed air travelling between a gas compressor/expander subsystem and an underground accumulator in a compressed air energy storage system operable in at least a charging mode and a discharging mode using at least a first reversible heat exchanger having a first gas flow path and a first liquid flow path, may include:

-   (a) directing the stream of compressed air from the gas     compressor/expander subsystem toward the     -   accumulator when in the charging mode, including directing the         compressed air through the first gas flow path in a gas charging         flow direction, and directing a thermal storage liquid through         the first liquid flow path in a liquid charging flow direction         from a thermal source reservoir toward a thermal storage         reservoir whereby at least a portion of the thermal energy in         the compressed air is transferred from the compressed air into         the thermal storage liquid within the first reversible heat         exchanger; and -   (b) directing the stream of compressed air from the accumulator     toward the gas compressor/expander     -   subsystem when in the discharging mode, including redirecting         the compressed air through the first gas flow path in a gas         discharging flow direction that is opposite the gas charging         flow direction and redirecting the thermal storage liquid         through the first liquid flow path in a liquid discharging flow         direction that is opposite the liquid charging flow direction         from the thermal storage reservoir toward the thermal source         reservoir whereby at least a portion of the thermal energy in         the thermal storage liquid is returned into the compressed air         within the first reversible heat exchanger.

The first gas flow path and the first liquid flow path may be configured so that when in the charging mode an inlet temperature of the compressed air entering the first reversible heat exchanger is within about 25° C. of an outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger.

When in the charging mode, an inlet temperature of the compressed air entering the first reversible heat exchanger may be within about 10° C. of an outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger.

When in the charging mode, an inlet temperature of the compressed air entering the first reversible heat exchanger may be within about 5° C. of an outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger.

The first reversible heat exchanger may have an approach temperature that is less than about 10° C.

The approach temperature may be less than about 5° C.

Step (a) may further comprise conveying the stream of compressed air in the gas charging flow direction through a plurality of tubes forming part of the first gas flow path within the first reversible heat exchanger and conveying the thermal storage liquid through an outer flow region within the first reversible heat exchanger that forms part of the first liquid flow path.

The compressed air may enter the plurality of tubes at a first pressure and exit the plurality of tubes at a second pressure that is at least 90% of the first pressure during the charging mode.

The second pressure may be between about 10 kPa and about 80 kPa less than the first pressure.

The second pressure may be within about 50 kPa of the first pressure.

Step (b) may further comprise conveying the stream of compressed air in the gas discharging flow direction through the plurality of tubes and wherein the compressed air enters the plurality of tubes at a first pressure and exits the plurality of tubes at a second pressure that is at least 85% of the first pressure.

During the discharging mode, the second pressure may be between about 10 kPa and about 80 kPa less than the first pressure.

During the discharging mode, the second pressure may be within about 50 kPa of the first pressure.

The first gas flow path and the first liquid flow path may be configured so that when in the charging mode the gas charging flow direction is opposite the liquid charging flow direction.

The first gas flow path and the first liquid flow path may be configured so that when in the discharging mode the gas discharging flow direction is opposite the liquid discharging flow direction.

The method may further comprise conveying the compressed air through the first gas flow path the same number of times as the thermal storage liquid is conveyed through the first liquid flow path during the charging mode and during the discharging mode.

The compressed air may flow through the first reversible heat exchanger only once during the charging mode.

The compressed air may flow through the first reversible heat exchanger only once during the discharging mode.

The first reversible heat exchanger may comprise at least first and second exchanger modules arranged in fluid communication in series with each other and step a) includes directing the flow of compressed air through the first exchanger module and then through the second exchanger module.

The first reversible heat exchanger may comprise at least first and second exchanger modules arranged in fluid communication in series with each other and step a) includes directing the flow of compressed air through the first exchanger module and the second exchanger module in parallel.

The compressor/expander subsystem may have at least two stages, and there may be at least two reversible heat exchangers, one for each stage of compression/expansion.

The first reversible heat exchanger may be a coil wound exchanger with at least two tube bundles, and the compressor/expander subsystem has at least two stages, where each of the at least two compression/expansion stages is connected to one of the at least two bundles such that the compressed gas path for multiple stages of compression/expansion are connected to one common heat exchanger.

The first reversible heat exchanger may comprise at least one of a shell-and-tube exchanger, coil wound exchanger (CWHE), plate-and-frame exchanger and braised plate exchanger.

The first reversible heat exchanger may comprise a single tube pass, single shell pass shell-and-tube heat exchanger comprising a plurality of tubes providing a portion of the first gas flow path surrounded by a shell flow path providing a portion of the first liquid flow path, and wherein the compressed air flows through the tubes and the thermal storage liquid flows through the shell flow path.

The accumulator may comprise a hydrostatically compensated accumulator and the method may further comprise:

-   (a) when in the charging mode, displacing a corresponding amount of     compensation liquid from the layer of compensation liquid out of the     accumulator toward a compensation liquid reservoir via a     compensation liquid flow path thereby maintaining the layer of     compressed air at substantially the storage pressure during the     charging mode; and -   (b) when in the discharging mode, providing a return flow of the     compensation liquid into the accumulator as the compressed air is     removed thereby maintaining the layer of compressed air at     substantially the storage pressure during the discharging mode.

In accordance with another broad aspect of the teachings described herein, a compressed air energy storage system alternately operable in at least a charging mode and a discharging mode, may include:

-   (a) an accumulator comprising an underground chamber having an     accumulator interior for containing compressed air at a storage     pressure; -   (b) a gas compressor/expander subsystem in fluid communication with     the accumulator interior via an air flow path and configured to     convey a flow of compressed air into the accumulator when in the     charging mode and out of the accumulator when in the discharging     mode; -   (c) a thermal storage subsystem comprising at least a first     reversible heat exchanger having a first liquid flow path forming     part of a thermal liquid flow path between a thermal source     reservoir and     -   a thermal storage reservoir and a first gas flow path forming         part of the air flow path between the gas compressor/expander         subsystem and the accumulator;

wherein the system is operable in at least:

-   a charging mode in which gas from the gas compressor/expander     subsystem is conveyed through the air flow path toward the     accumulator, including conveying the compressed air through the     first gas flow path in a gas charging flow direction, and directing     the thermal storage liquid through the first liquid flow path in a     liquid charging flow direction from the thermal source reservoir     toward the thermal storage reservoir whereby thermal energy is     transferred from the compressed air into the thermal storage liquid     within the first reversible heat exchanger, and wherein the     compressed air enters the accumulator at a storage pressure; and -   a discharging mode in which air exits the accumulator and is     conveyed through the air flow path toward the gas     compressor/expander subsystem, including conveying the compressed     air through the first gas flow path in a gas discharging flow     direction opposite the gas charging flow direction, and redirecting     the thermal storage liquid through the first liquid flow path in a     liquid discharging flow direction that is opposite the liquid     charging flow direction from the thermal storage reservoir toward     the thermal source reservoir whereby thermal energy is reintroduced     into the compressed air from the thermal storage liquid within the     first reversible heat exchanger.

The system may be operable in a storage mode in which there is no flow of the compressed air or thermal storage liquid and the compressed air is retained within the accumulator at the storage pressure.

The first gas flow path may comprise a plurality of tubes within the first reversible heat exchanger.

The plurality of tubes may each have a substantially constant and unobstructed cross-sectional flow area along their respective lengths.

During the charging mode an inlet temperature of the compressed air entering the first gas flow path may be within about 25° C. of an outlet temperature of the thermal storage liquid exiting the first liquid flow path.

During the charging mode the inlet temperature of the compressed air entering the first gas flow path may be within about 10° C. of the outlet temperature of the thermal storage liquid exiting the first liquid flow path.

During the charging mode the inlet temperature of the compressed air entering the first gas flow path may be within about 5° C. of the outlet temperature of the thermal storage liquid exiting the first liquid flow path.

During the charging mode an outlet temperature of the compressed air exiting the first gas flow path may between about 10° C. and about 30° C. of an inlet temperature of the thermal storage liquid entering the first gas flow path.

During the charging mode the outlet temperature of the compressed air exiting the first gas flow path may be less than 25° C. of the inlet temperature of the thermal storage liquid entering the first gas flow path.

During the discharging mode an outlet temperature of the air exiting the first gas flow path may be within about 25° C. of an inlet temperature of the thermal storage liquid entering the first liquid flow path.

During the discharging mode the outlet temperature of the air exiting the first gas flow path may be within about 10° C. of the inlet temperature of the thermal storage liquid entering the first liquid flow path.

During the discharging mode the outlet temperature of the air exiting the first gas flow path may be within about 5° C. of the inlet temperature of the thermal storage liquid entering the first liquid flow path.

The thermal storage subsystem may further comprise at least a second reversible heat exchanger having a second liquid flow path forming part of a thermal liquid flow path between the thermal source reservoir and the thermal storage reservoir and a second gas flow path forming part of the air flow path between the compressor/expander subsystem and the accumulator.

The second liquid flow path may be fluidly connected in parallel with the first liquid flow path.

The first liquid flow path may comprise an outer flow area surrounding and in contact with the plurality of tubes.

The system may further comprise at least one flow directing member extending into the outer flow area to direct the thermal storage liquid across the plurality of tubes.

The first reversible heat exchanger may comprise at least one of a shell-and-tube exchanger, coil wound exchanger (CWHE), plate-and-frame exchanger and braised plate exchanger.

The first reversible heat exchanger may comprise a single tube pass, single shell pass shell-and-tube heat exchanger comprising a plurality of tubes providing a portion of the first gas flow path surrounded by a shell flow path providing a portion of the first liquid flow path, and wherein the compressed air flows through the tubes and the thermal storage liquid flows through the shell flow path.

The first reversible heat exchanger may comprise a single tube pass, single shell pass CWHE exchanger comprising a plurality of tubes providing a portion of the first gas flow path surrounded by a shell flow path providing a portion of the first liquid flow path, and wherein the compressed air flows through the tubes and the thermal storage liquid flows through the shell flow path.

The first reversible heat exchanger may be vertically oriented, and when in the charging mode the compressed air enters at an upper end of the first reversible heat exchanger, flows in a generally downwardly direction through the first gas flow path and exits at a lower end of the first reversible heat exchanger.

When in the discharging mode the compressed air may ente at the lower end of the CWHE exchanger, flow in a generally upwardly direction through the first gas flow path and exit at the upper end of the CWHE exchanger.

Wen in the charging mode a pressure drop along the first gas flow path may be between about 10 kPa and about 100 kPa.

The pressure drop along the first gas flow path may be less than about 70 kPa.

The pressure drop along the first gas flow path may be less than about 50 kPa.

The pressure drop along the first gas flow path may be between about 20 kPa and about 30 kPa.

When in the discharging mode a pressure drop along the first gas flow path may be between about 10 kPa and about 100 kPa.

The pressure drop along the first gas flow path in the discharging mode may be less than about 70 kPa.

The pressure drop along the first gas flow path in the discharging mode may be less than about 50 kPa.

The pressure drop along the first gas flow path in the discharging mode may be between about 20 kPa and about 30 kPa.

The first reversible heat exchanger may be configured as a counterflow heat exchanger in which the gas charging flow direction is generally opposite the liquid charging flow direction.

The gas discharging flow direction may be generally opposite the liquid discharging flow direction.

The thermal source reservoir may be configured for containing the thermal storage liquid at a low storage temperature and the thermal storage reservoir is in communication with the thermal source reservoir via the thermal liquid flow path and is configured to contain the thermal storage liquid at a high storage temperature.

When in the charging mode the thermal storage liquid exiting the first liquid flow path may be at a temperature that is greater than a boiling temperature of the thermal storage liquid when at atmospheric pressure.

The thermal storage reservoir may be at least partially underground.

The thermal storage liquid may comprise at least one of water, mineral oil and synthetic oil.

The first reversible heat exchanger may include a first end at which the compressed air enters the first gas flow path during the charging mode and exits the first gas flow path during the discharging mode, and an opposing second end at which the compressed air exits the first gas flow path during the charging mode and enters the first gas flow path during the charging mode, and wherein the first end is at a higher temperature than the second end during both the charging and discharging modes.

The first end may be at a higher elevation than the second end.

The first reversible heat exchanger may comprise at least first and second exchanger modules arranged in fluid communication in series with each other and the compressed air flows through the first exchanger module and then through the second exchanger module in the gas charging flow direction when in the charging mode.

The compressed air may flow through the second exchanger module and then through the first exchanger module in the gas discharging flow direction when in the discharging mode.

During the discharging mode the air may exit the first gas flow path at between about 180 and 250° C.

During the charging mode the air may exit the first gas flow path at between about 30 and 70° C.

The compressed air energy storage system may comprise an underground hydrostatically compensated accumulator configured to contain a layer of compensation liquid beneath a layer of the compressed air at the storage pressure.

The system may further comprise a compensation liquid reservoir spaced apart from the accumulator and in fluid communication with the layer of compensation liquid within the accumulator via a compensation liquid flow path compensation whereby liquid can flow between the accumulator and the compensation liquid reservoir when in use.

During the charging mode the compressed air may enter the accumulator at a storage pressure which displaces a corresponding amount of compensation liquid from the layer of compensation liquid out of the accumulator via the compensation liquid flow path thereby maintaining the layer of compressed air at substantially the storage pressure during the charging mode.

During the discharging mode the compensation liquid may re-enter the accumulator via the compensation liquid flow path as air is removed from the accumulator thereby maintaining the layer of compressed air at substantially the storage pressure during the discharging mode.

During the storage mode there may be no flow of the compensation liquid into or out of the accumulator and the layer of compensation liquid is retained in the accumulator at least substantially the storage pressure.

The compressed air may flow alternatively through the at least two stages compressor/expander subsystem and the at least two reversible heat exchangers during the charging and discharging modes.

BRIEF DESCRIPTION OF THE DRAWINGS

The drawings included herewith are for illustrating various examples of articles, methods, and apparatuses of the teaching of the present specification and are not intended to limit the scope of what is taught in any way.

FIG. 1 is a schematic representation of one example of a hydrostatically compressed gas energy storage system;

FIG. 2 is a schematic representation of a portion of the system of FIG. 1

FIG. 3 is a schematic representation of another example of a hydrostatically compressed gas energy storage system;

FIG. 4 is a schematic view of components of an alternative compressor/expander subsystem for a compressed gas energy storage system, with pairs of compression and expansion stages each associated with a respective stage of a thermal storage subsystem;

FIG. 5 is a schematic view of components of the alternative compressor/expander subsystem of FIG. 4 , showing airflow during an expansion (discharging) phase from storage through multiple expanders and respective stages of a thermal storage subsystem;

FIG. 6 is a schematic view of components of the alternative compressor/expander subsystem of FIG. 4 , showing airflow during a compression (charging) phase from the ambient through multiple compressors and respective stages of a thermal storage subsystem;

FIG. 7 is a sectional view of components of a compressed gas energy storage system, according to an alternative embodiment;

FIG. 8 is a sectional view of components of an alternative compressed gas energy storage system, according to another alternative embodiment;

FIG. 9 is a schematic view of components of one embodiment of a compressor/expander subsystem for a compressed gas energy storage system, with three pairs of compression and expansion stages each associated with a respective stage of a thermal storage subsystem;

FIG. 10 is a schematic view of components of the three-stage compressor/expander subsystem of FIG. 9 , showing airflow and thermal fluid flow during a compression (charging) from the ambient through multiple compressors and respective stages of a thermal storage subsystem;

FIG. 11 is a schematic view of components of the three-stage compressor/expander subsystem of FIG. 9 , showing airflow and thermal fluid flow during an expansion (discharging) phase from storage through three expanders and respective stages of a thermal storage subsystem;

FIG. 12 is a schematic view of components of one embodiment of a compressor/expander subsystem and thermal storage subsystem for a compressed gas energy storage system which includes a series of reversible heat exchangers, during a charging phase;

FIG. 13 is a schematic view of components of one embodiment of a compressor/expander subsystem and thermal storage subsystem for a compressed gas energy storage system which includes a series of reversible heat exchangers, during a discharging phase;

FIG. 14 is a schematic view of components of one embodiment of reversible heat exchanger;

FIG. 15 is a schematic view of components of another embodiment of reversible heat exchanger;

FIG. 16 is graphical depiction of one embodiment of a preferable temperature profile for one or more reversible heat exchangers during charging mode; and

FIG. 17 is a graphical depiction of one embodiment of a preferable temperature profile for one or more reversible heat exchangers during discharging mode.

DETAILED DESCRIPTION

Various apparatuses or processes will be described below to provide an example of an embodiment of each claimed invention. No embodiment described below limits any claimed invention and any claimed invention may cover processes or apparatuses that differ from those described below. The claimed inventions are not limited to apparatuses or processes having all of the features of any one apparatus or process described below or to features common to multiple or all of the apparatuses described below. It is possible that an apparatus or process described below is not an embodiment of any claimed invention. Any invention disclosed in an apparatus or process described below that is not claimed in this document may be the subject matter of another protective instrument, for example, a continuing patent application, and the applicants, inventors or owners do not intend to abandon, disclaim or dedicate to the public any such invention by its disclosure in this document.

Energy produced by some types of energy sources, such as windmills, solar panels and the like may tend to be produced during certain periods (for example when it is windy, or sunny respectively), and not produced during other periods (if it is not windy, or at night, etc.). However, the demand for energy may not always match the production periods, and it may be useful to store the energy for use at a later time. Similarly, it may be helpful to store energy generated using conventional power generators (coal, gas and/or nuclear power plants for example) to help facilitate storage of energy generated during non-peak periods (e.g. periods when electricity supply could be greater than demand and/or when the cost of electricity is relatively high) and allow that energy to be utilized during peak periods (e.g. when the demand for electricity may be equal to or greater than the supply, and/or when the cost of electricity is relatively high).

As described herein, compressing and storing a gas (such as air), using a suitable compressed gas energy storage system, is one way of storing energy for later use. For example, during non-peak times, energy (i.e. electricity) can be used to drive compressors and compress a volume of gas to a desired, relatively high pressure for storage. The gas can then be stored at the relatively high pressure inside any suitable container or vessel, such as a suitable accumulator. To extract the stored energy, the pressurized gas can be released from the accumulator and used to drive any suitable expander apparatus or the like, and ultimately to be used to drive a generator or the like to produce electricity. The amount of energy that can be stored in a given compressed gas energy storage system may be related to the pressure at which the gas is compressed/ stored, with higher pressure storage generally facilitating a higher energy storage. However, containing gases at relatively high pressures in conventional systems, such as between about 45-150 atm, can require relatively strong, specialized and often relatively costly storage containers/pressure vessels.

When gas is compressed for storage (for example during a charging mode) its temperature tends to increase, and if the gas passes through multiple compression stages its temperature can increase with each stage. Further, some compressors may have a preferred inlet temperature range in which they operate with a desired level of efficiency. Gas that has been compressed in a one compression stage may, in some systems, be heated to a temperature that is above a desired inlet temperature for a subsequent compressions stage. Reducing the temperature of the gas exiting an upstream compressions stage before it reaches a subsequent compression stage may be advantageous.

Similarly, when compressed gas is removed from an accumulator and expanded for electricity generation (for example when in a discharge mode), the expansion process is endothermic and thermal energy is transferred into the expanding gas.

Optionally, heat that is removed/ extracted from the gas exiting one or more compression stages when the system is in a charging mode of the system can be stored in a suitable thermal storage subsystem, and preferably that heat/thermal energy can then be re-introduced into the gas that is removed from the accumulator and is passing through suitable expansion stages during the discharge mode. This may help improve the overall efficiency of a compressed gas energy storage system. This may also help reduce and/or eliminate the need for heat sinks/ sources or other apparatuses to dissipate heat when in the charging mode and/or supply new heat when in the discharge mode.

Thermal energy/ heat that is extracted from the compressed gas can be stored in any suitable thermal storage apparatus, including those described herein. Preferably, at least a portion of the thermal storage subsystem and/or thermal storage apparatus may be provided by adapting and/or repurposing one or more portions of the overall compressed gas energy storage system. For example, systems in which the accumulator and/or other system components are located underground may utilize one or more excavation shafts or similar structures during the construction phase to help transport equipment and personnel to the underground structures and/or to extract debris and other material from the construction sites. Shafts of this nature will generally extend from an upper end at the surface, or at least accessible from the surface during construction, to a lower end that is adjacent and at least temporarily connected to the underground structure/ cavern/ chamber, etc. that is being constructed. This can help facilitate the movement of equipment, people and debris. In some examples, more than one such shaft may be created for a variety of reasons, including to help expedite construction, provide two or more access and egress locations for safety-related reasons, provide underground ventilation and other such purposes. In some embodiments of the compressed gas energy storage systems described herein, these shafts may extend at least 100 m, 200 m, 300 m, 400 m or more into the ground, depending on the design constraints and soil conditions surrounding a given compressed gas energy storage systems. Such shafts may be generally referred to as excavation shafts even if their primary function is ventilation or access and even if no debris is actually extracted via the shaft during construction. Similarly, while the term “shaft” is used for convenience, the actual geometry of the structure may vary depending on the particular building techniques used, and may take the form of a decline, chamber or other such structure, and may be substantially vertical or may be inclined, and/or may be generally linear or may have a curved or varying geometry.

Shafts of this nature may be relatively costly and time consuming to create, and in known designs are generally not utilized when the completed compressed gas energy storage system is in use. Optionally, one or more of these shafts or other construction-phase legacy structures may be converted into part of the thermal storage subsystem. This may help reduce the overall cost of constructing the compressed gas energy storage system and may help reduce the overall size/ footprint of the compressed gas energy storage system. This may also, in some circumstances, help reduce the overall construction time for the compressed gas energy storage system, as at least some aspects of the thermal storage subsystem need not be separately constructed following the completion of the shaft(s) itself.

In one example, one or more of the excavation shafts may be configured as a reservoir that is configured to contain a suitable thermal storage media (such as a liquid, solid or the like) that can be used to receive and retain/store thermal energy from the compressed gas when in the charging mode, and optionally from gas exiting two or more compressor stages. For example, one or both of the ends of the shaft can be sealed using suitable structures to enclose the shaft interior and isolated from the surrounding atmosphere (if desired) and from other operating system components (e.g. the accumulator, gas conduits, and the like).

The thermal storage media can then be contained within the shaft until the system enters the discharge mode, at which point thermal energy can be returned from the thermal storage media contained in the shaft to the gas exiting the accumulator (and optionally prior to the inlet of two or more expanders). The thermal exchange between the gas and the thermal storage media may be achieved by way of any suitable direct and/or indirect heat exchanger, and the exchange may occur within the shaft itself or the thermal storage media may be passed through a heat exchanger that is external the shaft. If a liquid thermal storage media is used, the shaft or at least portions thereof may be pressurized to higher than atmospheric pressure to help allow the liquid to be heated past its boiling temperature at atmospheric pressure. This can help the system absorb more thermal energy than an analogous unpressurized system using the same thermal storage liquid.

It is noted that using some known construction techniques for creating such excavation and/or construction shafts may not produce shafts that are suitable for repurposing in this manner. For example, shafts that are to be repurposed to functional as thermal storage reservoir may be exposed to operating temperatures and pressures that are higher than would be expected during normal construction. Therefore, conventional shaft liners, grouts and construction materials may be unsuitable for use on the shafts as they may tend to be ineffective at retaining high temperature and/or high pressure materials, and/or may tend to degrade or fail under such conditions. Shafts that are constructed with a secondary repurposing in mind may be built with different materials that allow them to function satisfactorily as a construction shaft and that can provide suitable performance when reconfigured as a thermal storage reservoir. This may help reduce the need for further processing and/or refurbishing of the shafts.

Thermal storage subsystems that utilized repurposed shafts or other construction related apparatuses may used in combination with any suitable type of compressed gas energy storage system that utilizes an underground accumulator, including hydrostatically compensated compressed gas energy storage systems and compressed gas energy storage systems that are not hydrostatically compensated.

Alternatively, the thermal storage subsystem may not repurpose one or more portions of the overall compressed gas energy storage system, such as an excavation shaft, and may utilize a purpose built vessel for the containment of thermal storage media.

Referring to FIG. 1 one example of a hydrostatically compensated compressed gas energy storage system 10A, that can be used to compress, store and release a gas, includes an accumulator 12 that is located underground (although in another embodiment the accumulator may be located above ground). In this example, the accumulator 12 serves as a chamber for holding both compressed gas and a liquid (such as water) and can include any suitable type of pressure vessel or tank, or as in this example can be an underground cave or chamber that is within ground 200. In this embodiment, accumulator 12 is lined, for example using concrete, metal, plastic and combinations thereof or the like, to help make it substantially gas and/or liquid impermeable so as to help to prevent unwanted egress of gas or liquid from within the interior 23. In another embodiment, the accumulator is preferably impermeable to gas and or liquid without requiring a lining.

The accumulator 12 may have any suitable configuration, and in this example, includes an upper wall 13 and an opposing lower wall 15 that are separated from each other by an accumulator height 17. The upper and lower walls 13 and 15 may be of any suitable configuration, including curved, arcuate, angled, and the like, and in the illustrated example are shown as generally planar surfaces, that are generally parallel to a horizontal reference plane 19. The accumulator 12 also has an accumulator width (not shown - measured into the page as illustrated in FIG. 1 ). The upper and lower walls 13 and 15, along with one or more sidewalls 21 at least partially define an interior 23 of the accumulator 12, that has an accumulator volume.

The accumulator 12 in a given embodiment of the system 10A can be sized based on a variety of factors (e.g. the quantity of gas to be stored, the available space in a given location, etc.) and may, in some examples may be between about 1,000 m³ and about 2,000,000m³ or more. For example, in this embodiment the accumulator 12 contains a layer of stored compressed gas 14 atop a layer of liquid 16, and its volume (and thus capacity) can be selected based on the quantity of gas 14 to be stored, the duration of storage required for system 10A, and other suitable factors which may be related to the capacity or other features of a suitable power source and/or power load (see power source/load S/L in FIG. 2 ) with which the system 10A is to be associated. The power source/load S/L may be, in some examples, a power grid, a power source (including renewable and optionally non-renewable sources) and the like. Furthermore, the power source and power load may be completely independent of each other (e.g. the power source 25 may be a renewable source, and the power load may be the grid).

Preferably, the accumulator 12 may be positioned below ground or underwater, but alternatively may be at least partially above ground. Positioning the accumulator 12 within the ground 200, as shown, may allow the weight of the ground/soil to help backstop/ buttress the walls 13, 15 and 21 of the accumulator 12, and help resist any outwardly acting forces that are exerted on the walls 13, 15 and 21 of the interior 23 of the accumulator. Its depth in the ground is established according to the pressures at which the compression/expansion equipment to be used is most efficiently operated, the geology in the surrounding area and the like.

The gas that is to be compressed and stored in the accumulator 12 may be any suitable gas, including, but not limited to, air, nitrogen, noble gases and combinations thereof and the like. Using air may be preferable in some embodiments as a desired quantity of air may be drawn into the system from the surrounding, ambient environment and gas/air that is released from within the accumulator 12 can similarly be vented to the ambient environment, optionally without requiring further treatment. In this embodiment, the compressed gas 14 is compressed atmospheric air, and the liquid is water.

Optionally, to help provide access to the interior of the accumulator 12, for example for use during construction of the accumulator and/or to permit access for inspection and/or maintenance, the accumulator 12 may include at least one opening that can be sealed in a generally air/gas tight manner when the system 10A is in use. In this example, the accumulator 12 includes a primary opening 27 that is provided in the upper wall 13. The primary opening 27 may be any suitable size and may have a cross-sectional area (taken in the plane 19) that is adequate based on the specific requirements of a given embodiment of the system 10A. In one embodiment the cross-sectional area is between about 0.75 m2 and about 80 m2 but may be larger or smaller in a given embodiment.

When the system 10A is in use, the primary opening 27 may be sealed using any suitable type of partition that can function as a suitable sealing member. In the embodiment of FIG. 1 , the system 10A includes a partition in the form of a bulkhead 24 that covers the primary opening 27. Some examples of suitable partitions are described in PCT/CA2018/050112 and PCT/CA2018/050282, which are incorporated herein by reference.

When the bulkhead 24 is in place, as shown in FIG. 1 , it can be secured to, and preferably sealed with the accumulator wall, in this embodiment upper wall 13, using any suitable mechanism to help seal and enclose the interior 23. In other embodiments, the bulkhead 24 may have a different, suitable configuration.

The bulkhead 24 may be manufactured in situ, or may be manufactured offsite, and may be made of any suitable material, including, concrete, metal, plastics, composites and the like. In the illustrated embodiment, the bulkhead 24 is assembled in situ at the interface between a shaft 18 and the accumulator 12 of multiple pieces of reinforced concrete. In this embodiment the shaft 18 is illustrated schematically as a generally linear, vertical column. Alternatively, the shaft 18 may be a generally linear inclined shaft or preferably may be a curved and/or generally spiral/helical type configuration and which may be referred to as a shaft or generally as a decline. Some embodiments may include a generally spiralling configured decline that winds from an upper end to a lower end and can have an analogous function and attributes as the vertical shaft 18 of FIG. 1 despite having a different geometrical configuration. Discussions of the shaft/ decline 18 and its purposes in one embodiment can be applied to other embodiments described herein.

In the embodiment of FIG. 1 , the primary opening 27 is provided in the upper surface 13 of the accumulator 12. Alternatively, in other embodiments the primary opening 27 and any associated partition may be provided in different portions of the accumulator 12, including, for example, on a sidewall (such as sidewall 21 as shown in FIG. 3 ), in a lower surface (such as lower surface 15) or other suitable location. The location of the primary opening 27, and the associated partition, can be selected based on a variety of factors including, for example, the soil and underground conditions, the availability of existing structures (e.g. if the system 10A is being retrofit into some existing spaces, such as mines, quarries, storage facilities and the like), operating pressures, shaft configurations and the like. For example, some aspects of the systems 10A described herein may be retrofit into pre-existing underground chambers, which may have been constructed with openings in their sidewalls, floors and the like. Utilizing some of these existing formations may help facilitate construction and/or retrofit of the chambers used in the system and may reduce or eliminate the need to form additional openings in the upper surfaces of the chambers. Reducing the total number of openings in the accumulator may help facilitate sealing and may help reduce the chances of leaks and the like. In other embodiments, the components of the systems described herein may be purpose-built for the described purposes and may be configured in manner that helps facilitate both construction and operation of the systems.

When the primary opening 27 extends along the sidewall 21 of the accumulator 12 as shown in the embodiment of FIG. 3 , it may be positioned such that is contacted by only the gas layer 14 (i.e. toward the top of the accumulator 12), contacted by only the liquid layer 16 (i.e. submerged within the liquid layer 16 and toward the bottom of the accumulator) and/or by a combination of both the gas layer 14 and the liquid layer 16 (i.e. partially submerged and partially non-submerged in the liquid). The specific position of the free surface of the liquid layer 16 (i.e. the interface between the liquid layer 16 and the gas layer 14) may change while the system 10 is in use as gas is forced into (causing the liquid layer to drop) and/or withdrawn from the accumulator (allowing the liquid level to rise).

When the accumulator 12 is in use, at least one of the pressurized gas layer 14 and the liquid layer 16 may contact and exert pressure on the inner-surface 29 of the bulkhead 24, which will result in a generally outwardly, (upwardly in this embodiment) acting internal accumulator force, represented by arrow 41 in FIG. 1 , acting on the bulkhead 24. The magnitude of the internal accumulator force 41 acting on the partition may be at least partially dependent on the pressure of the gas 14 and the cross-sectional area (taken in plane 19) of the lower surface 29. For a given lower surface 29 area, the magnitude of the internal accumulator force 41 may vary generally proportionally with the pressure of the gas 14.

In some embodiments, for example if the compressed gas energy storage system is not hydrostatically compensated, the partition may be configured to resist substantially the entire internal accumulator force 41 and/or may be reinforced with the ground 200 or other suitable structures. Alternatively, an inwardly, (downwardly in this embodiment) acting force can be applied to the outer-surface 31 of the bulkhead 24 to help at least partially offset and/or counterbalance the internal accumulator force 41. Applying a counter force of this nature may help reduce the net force acting on the bulkhead 24 while the system 10 is in use. This may help facilitate the use of a bulkhead 24 with lower pressure tolerances than would be required if the bulkhead 24 had to resist the entire magnitude of the internal accumulator force 41. This may allow the bulkhead 24 be relatively smaller, lighter and less costly. This arrangement may also help reduce the chances of the bulkhead 24 failing while the system 10 is in use. Optionally, a suitable counter force may be created by subjecting the upper surface 31 to a pressurized environment, such as a pressurized gas or liquid or the distributed weight from a pile of solid material that is in contact with the upper surface 31, and calibrating the pressure acting on the upper surface 31 (based on the relative cross-sectional area of the upper surface 31 and the pressure acting on the lower surface 29) so that the resulting counter force, shown by arrow 46 in FIG. 1 , has a desirable magnitude. In some configurations, the magnitude of the counter force 46 may be between about 80% and about 99% of the internal accumulator force 41 and may optionally be between 5 about 90% and about 97% and may be about equal to the magnitude of the internal accumulator force 41.

In the present embodiment, the system 10 includes a shaft 18 that is configured so its lower end 43 is in communication with the opening 27 of the accumulator 12, and its upper end 48 that is spaced apart from the lower end 43 by a shaft height 50. At least one sidewall 52 extends from the lower end 43 to the upper end 48, and at least partially defines a shaft interior 54 having a volume. In this embodiment, the shaft 18 is generally linear and extends along a generally vertical shaft axis 51, but may have other configurations, such as a linear, curved, or helical decline, in other embodiments. The upper end 48 of the shaft 18 may be open to the atmosphere A, as shown, or may be capped, enclosed or otherwise sealed. In this embodiment, shaft 18 is generally cylindrical with a diameter 56 of about 3 metres, and in other embodiments the diameter 56 may be between about 2 m and about 15 m or more, or may be between about 5 m and 12 m, or between about 2 m and about 5 m. In such arrangements, the interior 52 of the shaft 18 may be able to accommodate about 1,000 - 150,000 m³ of water.

In this arrangement, the bulkhead 24 is positioned at the interface between the shaft 18 and the accumulator 12, and the outer surface 31 (or at least a portion thereof) closes and seals the lower end 43 of the shaft 18. Preferably, the other boundaries of the shaft 18 (e.g. the sidewall 52) are generally liquid impermeable, such that the interior 54 can be filled with, and can generally retain a quantity of a liquid, such as water 20. A water supply/replenishment conduit 58 can provide fluid communication between the interior 54 of the shaft 18 and a water source/sink 150 to allow water to flow into or out of the interior of the shaft 18 as required when the system 10 is in operational modes. Optionally, a flow control apparatus 59 (as shown in FIG. 1 ) may be provided in the water supply/replenishment conduit 58. The flow control apparatus 59 may include a valve, sluice gate, or other suitable mechanism. The flow control apparatus 59 can be open while the system 10 is in operational modes to help facilitate the desired flow of water between the shaft 18 and the water source/sink 150. Optionally, the flow control apparatus 59 can be closed to fluidly isolate the shaft 18 and the water source/sink 150 if desired. For example, the flow control apparatus 59 may be closed to help facilitate draining the interior 54 of the shaft 18 for inspection, maintenance or the like.

The water source/sink 150 may be of any suitable nature, and may include, for example a connection to a municipal water supply or reservoir, a purposely built reservoir, a storage tank, a water tower, and/or a natural body of water such as a lake, river or ocean, groundwater, or an aquifer. In the illustrated example, the water source/sink 150 is illustrated as a lake. Allowing water to flow through the conduit 58 may help ensure that a sufficient quantity of water 20 may be maintained with shaft 18 and that excess water 20 can be drained from shaft 18. The conduit 58 may be connected to the shaft 18 at any suitable location, and preferably is connected toward the upper end 48. Preferably, the conduit 58 can be positioned and configured such that water will flow from the source/sink 150 to the shaft 18 via gravity, and need not include external, powered pumps or other conveying apparatus. Although the conduit 58 is depicted in the figures as horizontal, it may be non-horizontal.

In this example, the water 20 in the shaft 18 bears against the outside of bulkhead 24 and is thereby supported atop bulkhead 24. The amount of pressure acting on the height 50 of the water column.

The layer of stored compressed air 14 underlying bulkhead 24 serves, along with the technique by which bulkhead 24 is stably affixed to the surrounding in the ground, in one alternative to surrounding stone in the ground at the interface between accumulator 12 and shaft 18, to support bulkhead 24 and the quantity of liquid contained within shaft 18.

Preferably, as will be described, the pressure at which the quantity of water 20 bears against bulkhead 24 can be maintained so that magnitude of the counter force 46 is equal, or nearly equal, to the magnitude of the internal accumulator force 41 exerted by the compressed gas in compressed gas layer 14 stored in accumulator 12. In the illustrated embodiment, system 10 is operated so as to maintain a pressure differential (i.e. the difference between gas pressure inside the accumulator 12 and the hydrostatic pressure at the lower end 43 of the shaft 18) below a threshold amount - an amount preferably between 0 and 4 Bar, such as 2 Bar - the resulting net force acting on the bulkhead 24. Maintaining the net pressure differential, and the related net force magnitude, below a threshold net pressure differential limit may help reduce the need for the bulkhead 24 to be very large and highly-reinforced, and accordingly relatively expensive. In alternative embodiments, using a relatively stronger bulkhead 24 and/or installation technique for affixing the bulkhead 24 to the accumulator 12 may help withstand relatively higher pressure and net pressure differential, but may be more expensive to construct and install, all other things being equal. Furthermore, the height 17 of the accumulator 12 may be important to the pressure differential: if the height 17 is about 10 metres, then the maximum upward pressure on the bulkhead 24 will be 1 Bar higher than the downward pressure on the bulkhead 24 from the water 20 in shaft 18. The maximum pressure differential that is experienced by bulkhead 24 may increase by about 0.1 bar for every meter that the height 17 of the accumulator 12 is increased.

Each of shaft 18 and accumulator 12 may be formed in ground 200 using techniques similar to those used for producing mineshafts and other underground structures.

To help maintain substantially equal outward and inward forces 41 and 46 respectively on the bulkhead 24, the system 10 may be utilized to help maintain a desired differential in accumulator and shaft pressures that is below a threshold amount. These pressures may be controlled by adding or removing gas from the compressed gas layer 14 in accumulator 12 using any suitable compressor/expander subsystem 100, and in turn conveying water between the liquid layer 16 in accumulator 12 and the water 20 in shaft 18.

In this embodiment, the system 10A includes a gas flow path that provides fluid communication between the compressor/expander subsystem 100 and the accumulator 12. The gas flow path may include any suitable number of conduits, passages, hoses, pipes and the like and any suitable equipment may be provided in (i.e. in air flow communication with) the gas flow path, including, compressors, extractors, heat exchangers, valves, sensors, flow meters and the like. Referring to the example of FIG. 1 , in this example the gas flow path includes a gas conduit 22 that is provided to convey compressed air between the compressed gas layer 14 and the compressor/expander subsystem 100, which can convert the potential energy of compressed air to and from electricity. Similarly, a liquid supply conduit 40 is configured to convey water between the liquid layer 16 and the water 20 in shaft 18. Each conduit 22 and 40 may be formed from any suitable material, including metal, the surrounding rock, plastic and the like.

In this example, the gas conduit 22 has an upper end 60 that is connected to the compressor/expander subsystem 100, and a lower end 62 that is in communication with the compressed gas layer 14. The gas conduit 22 is, in this example, positioned inside and extends within the shaft 18, and passes through the bulkhead 24 to reach the compressed gas layer 14. Positioning the gas conduit 22 within the shaft 18 may eliminate the need to bore a second shaft and/or access path from the surface to the accumulator 12. The positioning in the current embodiment may also leave the gas conduit 22 generally exposed for inspection and maintenance, for example by using a diver or robot that can travel through the water 20 within the shaft 18 and/or by draining some or all of the water from the shaft 18. Alternatively, as shown using dashed lines in FIG. 1 and in the embodiment of FIG. 3 , the gas conduit 22 may be external the shaft 18. Positioning the gas conduit 22 outside the shaft 18 may help facilitate remote placement of the compressor/expander subsystem 100 (i.e. it need not be proximate the shaft 18) and may not require the exterior of the gas conduit 22 (or its housing) to be submerged in water. This may also eliminate the need for the gas conduit 22 to pass through the partition that separates the accumulator 12 from the shaft 18.

The liquid supply conduit 40 is, in this example, configured with a lower end 64 that is submerged in the water layer 16 while the system 10 is in use and a remote upper end 66 that is in communication with the interior 54 of the shaft 18. In this configuration, the liquid supply conduit 40 can facilitate the exchange of liquid between the liquid layer 16 and the water 20 in the shaft 18. As illustrated in FIG. 1 , the liquid supply conduit 40 can pass through the bulkhead 24 (as described herein), or alternatively, as shown using dashed lines, may be configured to provide communication between the liquid layer 16 and the water 20, but not pas through the bulkhead 24.

In this arrangement, as more gas is transferred into the gas layer 14 during an accumulation cycle, and its pressure increases, in this alternative slightly, water in the water layer 16 can be displaced and forced upwards through the liquid supply conduit 40 into shaft 18 against the hydrostatic pressure of the water 20 in the shaft 18. More particularly, water can preferably freely flow from the bottom of accumulator 12 and into shaft 18, and ultimately may be exchanged with the source/sink 150 of water, via a replenishment conduit 58. Alternatively, any suitable type of flow limiting or regulating device (such as a pump, valve, orifice plate and the like) can be provided in the water conduit 40. When gas is removed from the gas layer 14, water can be forced from the shaft 18, through the water conduit 40, to refill the water layer 16. The flow through the replenishment conduit 58 can help ensure that a desired quantity of water 20 may be maintained within shaft 18 as water is forced into and out of the water layer 16, as excess water 20 can be drained from and make-up water can be supplied to the shaft 18. This arrangement can allow the pressures in the accumulator 12 and shaft 18 to at least partially, automatically re-balance as gas is forced into and released from the accumulator 12.

Preferably, the lower end 64 of the liquid supply conduit 40 is positioned so that it is and generally remains submerged in the liquid layer 16 while the system 10 is in operational modes and is not in direct communication with the gas layer 14. In the illustrated example, the lower wall 15 is planar and is generally horizontal (parallel to plane 19, or optionally arranged to have a maximum grade of between about 0.01% to about 1%, and optionally between about 0.5% and about 1%, from horizontal), and the lower end 64 of the liquid supply conduit 40 is placed close to the lower wall 15. If the lower wall 15 is not flat or not generally horizontal, the lower end 64 of the liquid supply conduit 40 is preferably located in a low point of the accumulator 12 to help reduce the chances of the lower end 64 being exposed to the gas layer 14.

Similarly, to help facilitate extraction of gas from the gas layer, the lower end 62 of the gas conduit 22 is preferably located close to the upper wall 13, or if the upper wall 13 is not flat or generally horizontal at a high-point in the interior 23 of the accumulator 12. This may help reduce material trapping of any gas in the accumulator 12. For example, if the upper wall 13 were oriented on a grade, the point at which gas conduit 22 interfaces with the gas layer (i.e. its lower end 62) should be at a high point in the accumulator 12, to help avoid significant trapping of gas.

In the embodiment of FIG. 1 , the partition includes a fabricated bulkhead 24 that is positioned to cover, and optionally seal the primary opening 27 in the accumulator perimeter. Alternatively, in other embodiments, the partition may be at least partially formed from natural materials, such as rock and the like. For example, a suitable partition may be formed by leaving and/or shaping portions of naturally occurring rock to help form at least a portion of the pressure boundary between the interior of the accumulator and the shaft. Such formations may be treated, coated or otherwise modified to help ensure they are sufficiently gas impermeable to be able to withstand the desired operating pressure differentials between the accumulator interior and the shaft. This may be done, in some embodiments, by selectively excavating the shaft 18 and accumulator 12 such that a portion of the surrounding rock is generally undisturbed during the excavation and construction of the shaft 18 and accumulator 12. Alternatively, rock or other such material may be re-introduced into a suitable location within the accumulator 12 and/or shaft 18 after having been previously excavated. This may help reduce the need to manufacture a separate bulkhead and install it within the system 10. In arrangements of this nature, the primary opening 27 may be formed as an opening in a sidewall 21 of the accumulator 12, or alternatively one side of the accumulator 12 may be substantially open such that the primary opening 27 extends substantially the entire accumulator height 17, and forms substantially one entire side of the accumulator 12.

When the accumulator 12 is in use, at least one of the pressurized gas layer 14 and the liquid layer 16, or both, may contact and exert pressure on the inner-surface 29 of the bulkhead 24, which will result in a generally outwardly, (upwardly in this embodiment) acting internal accumulator force, represented by arrow 41 in FIG. 1 , acting on the bulkhead 24. The magnitude of the internal accumulator force 41 is dependent on the pressure of the gas 14 and the cross-sectional area (taken in plane 19) of the lower surface 29. For a given lower surface 29 area, the magnitude of the internal accumulator force 41 may vary generally proportionally with the pressure of the gas 14.

Preferably, an inwardly, (downwardly in this embodiment) acting force can be applied to the outer-surface 31 of the bulkhead 24 to help offset and/or counterbalance the internal accumulator force 41. Applying a counter force of this nature may help reduce the net force acting on the bulkhead 24 while the system 10 is in use. This may help facilitate the use of a bulkhead 24 with lower pressure tolerances than would be required if the bulkhead 24 had to resist the entire magnitude of the internal accumulator force 41. This may allow the bulkhead 24 be relatively smaller, lighter and less costly. This arrangement may also help reduce the chances of the bulkhead 24 failing while the system 10 is in use. Optionally, a suitable counter force may be created by subjecting the upper surface 31 to a pressurized environment, such as a pressurized gas or liquid that is in contact with the upper surface 31, and calibrating the pressure acting on the upper surface 31 (based on the relative cross-sectional area of the upper surface 31 and the pressure acting on the lower surface 29) so that the resulting counter force, shown by arrow 46 in FIG. 1 , has a desirable magnitude. In some configurations, the magnitude of the counter force 46 may be between about 80% and about 99% of the internal accumulator force 41 and may optionally be between about 90% and about 97% and may be about equal to the magnitude of the internal accumulator force 41.

In the present embodiment, the system 10 includes a shaft 18 having a lower end 43 that is in communication with the opening 27 in the upper wall 13 of the accumulator 12, and an upper end 48 that is spaced apart from the lower end 43 by a shaft height 50. At least one sidewall 52 extends from the lower end 43 to the upper end 48, and at least partially defines a shaft interior 54 having a volume. In this embodiment, the shaft 18 is generally linear and extends along a generally vertical shaft axis 51, but may have other configurations, such as a linear or helical decline, in other embodiments. The upper end 48 of the shaft 18 may be open to the atmosphere A, as shown, or may be capped, enclosed or otherwise sealed. In this embodiment, shaft 18 is generally cylindrical with a diameter 56 of about 3 metres, and in other embodiments the diameter 56 may be between about 2 m and about 15 m or more, or may be between about 5 m and 12 m, or between about 2 m and about 5 m. In such arrangements, the interior 52 of the shaft 18 may be able to accommodate about 1,000 - 150,000 m³ of water. In other embodiments the shaft need not be cylindrical and may have other cross-sectional geometries with the same hydraulic diameter.

In this arrangement, the bulkhead 24 is positioned at the interface between the shaft 18 and the accumulator 12, and the outer surface 31 (or at least a portion thereof) closes and seals the lower end 43 of the shaft 18. Preferably, the other boundaries of the shaft 18 (e.g. the sidewall 52) are generally liquid impermeable, such that the interior 54 can be filled with, and can generally retain a quantity of a liquid, such as water 20. A water supply/replenishment conduit 58 can provide fluid communication between the interior 54 of the shaft 18 and a water source/sink 150 to allow water to flow into or out of the interior of the shaft 18 as required when the system 10 is in use. Optionally, a flow control valve 59 (as shown in FIG. 1 ) may be provided in the water supply/replenishment conduit 58. The flow control valve 59 can be open while the system 10 is in use to help facilitate the desired flow of water between the shaft 18 and the water source/sink 150. Optionally, the flow control valve 59 can be closed to fluidly isolate the shaft 18 and the water source/sink 150 if desired. For example, the flow control valve 59 may be closed to help facilitate draining the interior 54 of the shaft 18 for inspection, maintenance or the like.

The water source/sink 150 may be of any suitable nature, and may include, for example a connection to a municipal water supply or reservoir, a purposely built reservoir, a storage tank, a water tower, and/or a natural body of water such as a lake, river or ocean, groundwater, or an aquifer. In the illustrated example, the water source/sink 150 is illustrated as a lake. Allowing water to flow through the conduit 58 may help ensure that a sufficient quantity of water 20 may be maintained with shaft 18 and that excess water 20 can be drained from shaft 18. The conduit 58 may be connected to the shaft 18 at any suitable location, and preferably is connected toward the upper end 48. Preferably, the conduit 58 can be positioned and configured such that water will flow from the source/sink 150 to the shaft 18 via gravity, and need not include external, powered pumps or other conveying apparatus. Although the conduit 58 is depicted in the figures as horizontal, it may be non-horizontal.

In this example, the water 20 in the shaft 18 bears against the outside of bulkhead 24 and is thereby supported atop bulkhead 24. The amount of pressure acting on the outer surface 31 of the bulkhead 24 in this example will vary with the volume of water 20 that is supported, which for a given diameter 56 will vary with the height 50 of the water column. In this arrangement, the magnitude of the counter force 46 can then be generally proportional to the amount of water 20 held in the shaft 18. To increase the magnitude of the counter force 46, more water 20 can be added. To reduce the magnitude of the counter force 46, water 20 can be removed from the interior 54.

The layer of stored compressed air 14 underlying bulkhead 24 serves, along with the technique by which bulkhead 24 is stably affixed to the surrounding in the ground, in one alternative to surrounding stone in the ground at the interface between accumulator 12 and shaft 18, to support bulkhead 24 and the quantity of liquid contained within shaft 18.

Preferably, as will be described, the pressure at which the quantity of water 20 bears against bulkhead 24 and can be maintained so that magnitude of the counter force 46 is as equal, or nearly equal, to the magnitude of the internal accumulator force 41 exerted by the compressed gas in compressed gas layer 14 stored in accumulator 12. In the illustrated embodiment, operating system 10 so as to maintain a pressure differential (i.e. the difference between gas pressure inside the accumulator 12 and the hydrostatic pressure at the lower end 43 of the shaft 18) within a threshold amount - an amount preferably between 0 and 4 Bar, such as 2 Bar - the resulting net force acting on the bulkhead 24 (i.e. the difference between the internal accumulator force 41 and the counter force 46) can be maintained below a pre-determined threshold net force limit. Maintaining the net pressure differential, and the related net force magnitude, below a threshold net pressure differential limit may help reduce the need for the bulkhead 24 to be very large and highly-reinforced, and accordingly relatively expensive. In alternative embodiments, using a relatively stronger bulkhead 24 and/or installation technique for affixing the bulkhead 24 to the accumulator 12 may help withstand relatively higher pressure and net pressure differential, but may be more expensive to construct and install, all other things being equal. Furthermore, the height 17 of the accumulator 12 may be important to the pressure differential: if the height 17 is about 10 metres, then the upward pressure on the bulkhead 24 will be 1 Bar higher than the downward pressure on the bulkhead 24 from the water 20 in shaft 18.

Each of shaft 18 and accumulator 12 may be formed in the ground 200 using any suitable techniques, including techniques that are similar to those used for producing mineshafts and other underground structures.

In this embodiment, a gas conduit 22 is provided to convey compressed air between the compressed gas layer 14 and the compressor/expander subsystem 100, which can convert compressed air energy to and from electricity. Similarly, a liquid conduit 40 is configured to convey water between the liquid layer 16 and the water 20 in shaft 18. Each conduit 22 and 40 may be formed from any suitable material, including metal, plastic and the like.

In this example, the gas conduit 22 has an upper end 60 that is connected to the compressor/expander subsystem 100, and a lower end 62 that is in communication with the gas layer 14. The gas conduit 22 is, in this example, positioned inside and extends within the shaft 18, and passes through the bulkhead 24 to reach the gas layer 14. Positioning the gas conduit 22 within the shaft 18 may eliminate the need to bore a second shaft and/or access point from the surface to the accumulator 12. This position may also leave the gas conduit 22 generally exposed for inspection and maintenance, for example by using a diver or robot that can travel through the water 20 within the shaft 18 and/or by draining some or all of the water from the shaft 18. Alternatively, as shown using dashed lines in FIG. 1 and in the embodiment of FIG. 17 , the gas conduit 22 may be external the shaft 18. Positioning the gas conduit 22 outside the shaft 18 may help facilitate remote placement of the compressor/expander subsystem 100 (i.e. it need not be proximate the shaft 18) and may not require the exterior of the gas conduit 22 (or its housing) to be submerged in water. This may also eliminate the need for the gas conduit 22 to pass through the partition that separates the accumulator 12 from the shaft 18.

FIG. 2 is a schematic view of components of one example of a compressor/expander subsystem 100 for the compressed gas energy storage system 10 described herein. In this example, the compressor/expander subsystem 100 includes a compressor 112 of single or multiple stages, driven by a motor 110 that is powered, in one alternative, using electricity from a power grid or by a renewable power source or the like, and optionally controlled using a suitable controller 118. Compressor 112 is driven by motor 110 during an accumulation stage of operation, and draws in atmospheric air A, compresses the air, and forces it down into gas conduit 22 for storage in accumulator 12 (via thermal storage subsystem 120 (see FIG. 1 for example) in embodiments including same). Compressor/expander subsystem 100 also includes an expander 116 driven by compressed air exiting from gas conduit 22 during an expansion stage of operation and, in turn, driving generator 114 to generate electricity. After driving the expander 116, the expanded air is conveyed for exit to the atmosphere A. While shown as separate apparatuses, the compressor 112 and expander 116 may be part of a common apparatus, as can a hybrid motor/generator apparatus. Optionally, the motor and generator may be provided in a single machine.

Air entering or leaving compressor/expander subsystem 100 may be conditioned prior to its entry or exit. For example, air exiting or entering compressor/ expander subsystem 100 may be heated and/or cooled to reduce undesirable environmental impacts or to cause the air to be at a temperature suited for an efficient operating range of a particular stage of compressor 112 or expander 116. For example, air (or other gas being used) exiting a given stage of a compressor 112 may be cooled prior to entering a subsequent compressor stage and/or the accumulator 12, and/or the air may be warmed prior to entering a given stage of an expander 116 and may be warmed between expander stages in systems that include two or more expander stages arranged in series.

Controller 118 operates compressor/expander subsystem 100 so as to switch between accumulation and expansion stages as required, including operating valves for preventing or enabling release of compressed air from gas conduit 22 on demand.

Optionally, the system 10A may include a thermal storage subsystem 120 (illustrated schematically in FIG. 1 ) that is configured to transfer heat/ thermal energy out of and preferably also into the gas flowing through the gas flow path between the accumulator and the compressor/expander subsystem 100. Preferably, the thermal storage subsystem 120 is configured to extract thermal energy from the gas exiting at least one of the one or more compression stages in a given compressor/expander subsystem 100, and preferably being configured to extract heat from the gas exiting each compression stage 112. The extracted thermal energy can then be stored for a period of time, and then reintroduced into the gas as it is removed from the accumulator 12 and passed through one or more expanders 116.

FIG. 3 is a schematic representation of another example of a compressed gas energy storage system 10B with a thermal storage subsystem 120 that is provided in the gas flow path between the compressor/expander subsystem 100 and the accumulator 12. The compressed gas energy storage system 10B is analogous to the compressed gas energy storage system 10A, and like features are identified using like reference characters. While one example is explained herein, other suitable thermal storage subsystems may be utilized in other embodiments, including those described in PCT/CA2018/050112 and PCT/CA2018/050282, which are incorporated herein by reference. The thermal storage subsystem 120 may also be used in combination with the systems 10A and 10B, and other systems described herein.

In the example of FIG. 3 , the gas conduit 22 that conveys the compressed gas between the compressed gas layer 14 and compressor/expander subsystem 100 includes an upper portion 22A that extends between the compressor/expander subsystem 100 and thermal storage subsystem 120, and a lower portion 22B that extends between thermal storage subsystem 120 and accumulator 12.

The thermal storage subsystem 120 may include any suitable type of thermal storage apparatus, including, for example latent and/or sensible storage apparatuses. The thermal storage apparatus(es) may be configured as single stage, two stage and/or multiple stage storage apparatus(es). Similarly, the thermal storage subsystem 120 may include one or more heat exchangers (to transfer thermal energy into and/or out of the thermal storage subsystem 120) and one or more storage apparatuses (including, for example storage reservoirs for holding thermal storage fluids and the like). Any of the thermal storage apparatuses may either be separated from or proximate to their associated heat exchanger and may also incorporate the associated heat exchanger in a single compound apparatus (i.e. in which the heat exchanger is integrated within the storage reservoir). Preferably, the heat exchangers utilized in the thermal storage subsystem 120 are provided in the gas flow path and are operable to transfer thermal energy between the compressed gas travelling through the gas flow path and the thermal storage media (which may be a solid, liquid or gas).

The exchangers may be any suitable type of heat exchanger for a given type of thermal storage media, and may include, for example, indirect heat exchangers or direct heat exchangers. The preferable type of heat exchanger for a given system may depend on a variety of factors and/or elements of the system. For example, a direct heat exchanger (i.e. that permits direct contact between the two sides/streams of the exchanger) may help facilitate for more conductivity between the compressed gas and thermal storage media and may, under some circumstances, be relatively more efficient in transferring thermal energy between the two than a comparable indirect heat exchanger. A direct heat exchanger may be preferred when using solid thermal storage media, such as rocks or gravel and may also be used in combination with a thermal storage liquid if both the gas and liquid streams are maintained under suitable conditions to help maintain the thermal storage liquid in its liquid state, and to avoid boiling and/or mixing of the gas stream and liquid stream.

An indirect heat exchanger may be preferable in systems in which the compressed gas is to be kept separate from the thermal storage media, such as if the thermal storage media needs to be kept under specific conditions, including pressure and/or if both streams in the heat exchanger are gaseous (or would boil if a liquid) such that there would be a mixing of the thermal storage media and the compressed system gas within the heat exchanger.

In the illustrated embodiment, substantial portions of the thermal storage subsystem 120 are located underground, which may help reduce the use of above-ground land and may help facilitate the use of the weight of the earth/rock to help contain the pressure in the storage reservoir. That is, the outward-acting pressure within the storage reservoir containing the heated and, optionally non-heated thermal storage media, can be substantially balanced by the inwardly-acting forces exerted by the earth and rock surrounding the first reservoir. In some examples, if a liner or other type of vessel are provided in the storage reservoir such structures may carry some of the pressure load but are preferably backed-up by and/or supported by the surrounding earth/rock. This can help facilitate pressurization of the storage reservoir to the desired storage pressures, without the need for providing a manufactured pressure vessel that can withstand the entire pressure differential. In this example, the thermal storage subsystem 120 also employs multiple stages including, for example, multiple sensible and/or latent thermal storage stages such as stages having one or more phase change materials and/or pressurized water, or other heat transfer fluid arranged in a cascade. It will be noted that, if operating the system for partial storage/retrieval cycles, the sizes of the stages may be sized according to the time cycles of the phase change materials so that the phase changes, which take time, take place effectively within the required time cycles.

Alternatively, the thermal storage subsystem 120 may be located entirely above ground. In some examples, the thermal storage media may be contained in purpose-built vessels which are designed to contain the thermal storage media at the desired storage pressure.

In general, as gas is compressed by the compressor/expander subsystem 100 when in the charging mode and is conveyed for storage towards accumulator 12, at least a portion of the heat from the compressed gas can be drawn out of the compressed gas and into the thermal storage subsystem 120 for sensible and/or latent heat storage. In this way, at least a portion of the heat energy is saved for future use instead of, for example being leached out of the compressed gas into water 20 or in the liquid layer 16, and accordingly substantially lost (i.e. non-recoverable by the system 10).

Similarly, when in a discharge mode as gas is released from accumulator 12 towards compressor/expander subsystem 100 it can optionally be passed through thermal storage subsystem 120 to re-absorb at least some of the stored heat energy on its way to the expander stage of the compressor/expander subsystem 100. Advantageously, the compressed gas, accordingly heated, can reach the compressor/expander subsystem 100 at a desired temperature (an expansion temperature - that is preferably warmer/higher than the accumulator temperature) that may help enable the expander to operate within its relatively efficient operating temperature range(s), rather than having to operate outside of the range with cooler compressed gas.

In some embodiments, the thermal storage subsystem 120 may employ at least one phase change material, preferably multiple phase change materials, multiple stages and materials that may be selected according to the temperature rating allowing for the capture of the latent heat. Generally, phase change material heat can be useful for storing heat of approximately 150° C. and higher. The material is fixed in location and the compressed air to be stored or expanded is flowed through the material. In embodiments using multiple cascading phase change materials, each different phase change material represents a storage stage, such that a first type of phase change material may change phase thereby storing the heat at between 200 and 250° C., a second type of phase change material may change phase thereby storing the heat at between 175 and 200 degree C, and a third type of phase change material may change phase thereby storing the heat at between 150 and 175° C. One example of a phase change material that may be used with some embodiments of the system includes a eutectic mixture of sodium nitrate and potassium nitrate, or the HITEC® heat transfer salt manufactured by Coastal Chemical Co. of Houston, Texas.

In embodiments of the thermal storage subsystem 120 employing sensible heat storage, pressurized water, or any other suitable thermal storage fluid/liquid and/or coolant, may be employed as the sensible thermal storage medium. Optionally, such systems may be configured so that the thermal storage liquid remains liquid while the system 10A or 10B is in use and does not undergo a meaningful phase change (i.e. does not boil to become a gas). This may help reduce the loss of thermal energy via the phase change process. For example, such thermal storage liquids (e.g. water) may be pressurized and maintained at an operating pressure that is sufficient to generally keep the water in its liquid phase during the heat absorption process as its temperature rises. That is, the reservoir and/or conduits containing a thermal storage liquid can be pressurized to a pressure that is greater than atmospheric pressure, and optionally may be at least between about 10 and 60 bar, and may be between about 30 and 45 bar, and between about 20 and 26 bar, so that the thermal storage liquid can be heated to a temperature that is greater than its boiling temperature at atmospheric pressure. Preferably, the thermal storage liquid may be pressurized in the thermal storage reservoir by allowing a portion of the heated thermal liquid to vaporize and pressurize the headspace of the thermal storage reservoir.

Optionally, the thermal fluid may be passed through a heat exchanger or series of heat exchangers to capture and return the heat to and from the gas stream that is exiting the accumulator, via conduit 22. Generally, sensible heat storage may be useful for storing heat of temperatures of 100° C. and higher. Pressurizing the thermal fluid, which may preferably be water, in these systems may help facilitate heating the thermal fluid to temperatures well above 100° C. (thereby increasing its total energy storage capability) without boiling.

Optionally, in some embodiments, a thermal storage subsystem 120 may combine both latent and sensible heat storage stages and may use phase change materials with multiple stages or a single stage. Preferably, particularly for phase change materials, the number of stages through which air is conveyed during compression and expansion may be adjustable by controller 118. This may help the system 10 to adapt its thermal storage and release programme to match desired and/or required operating conditions.

Optionally, at least some of the gas conduit 22 may be external the shaft 18 so that it is not submerged in the water 20 that is held in the shaft 18. In some preferred embodiments, the compressed gas stream will transfer its thermal energy to the thermal storage system 120 (for example by passing through heat exchangers 635 described herein) before the compressed gas travels underground. That is, some portions of the thermal storage subsystem 120 and at least the portion of the gas conduit that extends between the compressor/expander subsystem 100 and the thermal storage subsystem 120 may be provided above ground, as it may be generally desirable in some embodiments to transfer as much excess heat from the gas to the thermal storage subsystem 120, and reduce the likelihood of heat being transferred/lost in the water 20, ground or other possible heat sinks along the length of the gas conduit 22. Similar considerations can apply during the expansion stage, as it may be desirable for the warmed gas to travel from the thermal storage subsystem 120 to the compressor/ expander subsystem 100 at a desired temperature, while reducing the heat lost in transit.

Referring again to FIG. 3 , in this example the thermal storage subsystem 120 is configured to store thermal energy from the incoming pressurized gas in a thermal storage liquid 600. Optionally, the thermal storage liquid 600 can be pressurized in the thermal storage subsystem 120 to a storage pressure that is higher than atmospheric pressure and may optionally be generally equal to or greater than the accumulator pressure.

Pressurizing the thermal storage liquid 600 in this manner may allow the thermal storage liquid 600 to be heated to relatively higher temperatures (i.e. store relatively more thermal energy and at a more valuable grade) without boiling, as compared to the same liquid at atmospheric pressure. That is, the thermal storage liquid 600 may be pressurized to a storage pressure and heated to a thermal storage temperature such that the thermal storage liquid 600 is substantially maintained as a liquid while the system is in use (which may help reduce energy loss through phase change of the thermal storage liquid). In the embodiments illustrated, the storage temperature may be between about 150 and about 500° C., and preferably may be between about 150 and 350° C. The storage temperature is preferably below a boiling temperature of the thermal storage liquid 600 when at the storage pressure but may be, and in some instances preferably will be the above boiling temperature of the thermal storage liquid 600 if it were at atmospheric pressure. In this example, the thermal storage liquid 600 can be water, but in other embodiments may be engineered heat transfer/storage fluids, coolants, oils and the like. When sufficiently pressurized, water may be heated to a storage temperature of about 250° C. or higher without boiling, whereas water at that temperature would boil at atmospheric pressure.

Optionally, the thermal storage liquid 600 can be circulated through a suitable heat exchanger to receive heat from the compressed gas stream travelling through the gas supply conduit 22 during a charging mode (downstream from the compressor/expander subsystem 100). The heated thermal storage liquid 600 can then be collected and stored in a suitable storage reservoir (or more than one storage reservoirs) that can retain the heated thermal storage liquid 600 and can be pressurized to a storage pressure that is greater than atmospheric pressure (and may be between about 10 and 60 bar, and may be between about 30 and 45 bar, and between about 20 and 26 bar).

The storage reservoir may be any suitable type of structure, including an underground chamber/cavity (e.g. formed within the surrounding ground 200) or a fabricated tank, container, a combination of a fabricated tank and underground chamber/cavity, or the like. If configured to include an underground chamber, the chamber may optionally be lined to help provide a desired level of liquid and gas impermeability and/or thermal insulation. For example, underground chambers may be at least partially lined with concrete, polymers, rubber, plastics, geotextiles, composite materials, metal and the like. Configuring the storage reservoir to be at least partially, and preferably at least substantially impermeable may help facilitate pressurizing the storage reservoir as described herein. Preferably, the underground chamber may be a repurposed or reconfigured structure that was previously used for another purpose during the construction or operation of the system 10. For example, a thermal storage reservoir may be provided in the interior of a construction shaft or decline or other such structure that was used for a non-thermal storage related purpose during the construction of the system 10.

Fabricated tanks may be formed from any suitable material, including concrete, metal, plastic, glass, ceramic, composite materials and the like. Optionally, the fabricated tank may include concrete that is reinforced using, metal, fiber reinforced plastic, ceramic, glass or the like, which may help reduce the thermal expansion difference between the concrete and the reinforcement material.

In this embodiment the storage reservoir 610 of the thermal storage subsystem 120 includes a chamber 615 that is positioned underground, at a reservoir depth 660. Preferably, the reservoir depth 660 is less than or equal to the depth of the accumulator 12, which in this example corresponds to the shaft height 50. Optionally, the thermal storage subsystem 120 can be configured so that the reservoir depth 660 is at least about ⅓ of the accumulator depth/ shaft height 50, or more. For example, if the accumulator 12 is at a depth of about 300 m, the reservoir depth 660 is preferably about 100 m or more. For example, having the reservoir depth 660 being less than the accumulator depth 50 may help facilitate sufficient net positive suction head to be available to the fluid transfer pumps and other equipment utilized to pump the thermal storage liquid 600 through the thermal storage subsystem 120 (for example between source reservoir 606 and storage reservoir 610). This may allow the transfer pumps to be positioned conveniently above ground and may help reduce the chances of damaging cavitation from occurring.

The reservoir depth 660 being at least ⅓ the depth 50 of the accumulator 12 may also allow for relatively higher rock stability of the subterranean thermal storage cavern, such as chamber 615. The geostatic gradient, which provides an upper limit on pressure inside underground rock caverns, is typically about 2.5 - 3 times the hydrostatic gradient. Given this rock stability criterion, the shallowest reservoir depth 660 may be approximately three times less than the accumulator depth in some embodiments, such as when the storage pressure is generally equal than the accumulator pressure.

In this example, the chamber 615 is a single chamber having a chamber interior 616 that is at least partially defined by a bottom chamber wall 620, a top chamber wall 651, and a chamber sidewall 621. The chamber 615 is connected to one end of a liquid inlet/outlet passage 630 (such as a pipe or other suitable conduit) whereby the thermal storage liquid 600 can be transferred into and/or out of the chamber 615. In addition to the layer of thermal storage liquid 600, a layer of cover gas 602 is contained in the chamber 615 and overlies the thermal storage liquid 600. Like the arrangement used for the accumulator 12, the layer of cover gas 602 can be pressurized using any suitable mechanism to help pressurize the interior of the chamber 615 and thereby help pressurize the thermal storage liquid 600. Optionally, at least the subterranean portions of the liquid inlet/outlet passage 630 (i.e. the portions extending between the heat exchanger 635 and the storage reservoir 610) may be insulated (such as by a vacuum sleeve, or insulation material) to help reduce heat transfer between the thermal storage fluid and the surrounding ground.

When the thermal storage subsystem 120 is in use, a supply of thermal storage liquid can be provided from any suitable thermal storage liquid source 605. The thermal storage liquid source can be maintained at a source pressure that may be the same as the storage pressure or may be different than the storage pressure. For example, the thermal storage liquid source may be at approximately atmospheric pressure, which may reduce the need for providing a relatively strong, pressure vessel for the thermal storage liquid source. Alternatively, the thermal storage liquid source may be pressurized. The thermal storage liquid source may also be maintained at a source temperature that is lower, and preferably substantially lower than the storage temperature. For example, the thermal storage liquid source may be at temperatures of between about 2 and about 100° C. and may be between about 4 and about 50° C. Increasing the temperature difference between the incoming thermal storage liquid from the source and the storage temperature may help increase the amount of heat and/or thermal energy that can be stored in the thermal storage subsystem 120.

The thermal storage liquid source 605 may have any suitable configuration and may have the same construction as an associated storage reservoir or may have a different configuration. For example, in the embodiment of FIG. 3 the thermal storage liquid source 605 includes a source reservoir 606 that is configured in the same underground chamber as the thermal fluid storage chamber 615. In this arrangement, a closed loop system can be provided, including the storage reservoir 610 and the source reservoir 606. Alternatively, the thermal storage liquid source 605 may include a source reservoir 606 that is configured as an above-ground vessel, and optionally need not be pressurized substantially above atmospheric pressure. In other embodiments, the thermal liquid source 605 may include a body of water such as the lake 150, water 20 from the shaft 18, liquid from the liquid layer 16 in the accumulator 12 (or from any other portion of the overall system 10), water from a municipal water supply or other such sources and combinations thereof.

In the embodiment of FIG. 3 , the source reservoir 606 and storage reservoir 610 are adjacent each other and are portions of a generally common underground chamber. This may help simplify construction of the thermal storage subsystem 120 as an excavation of a single chamber may provide space for both the source reservoir 606 and storage reservoir 610. This may also help simplify piping and valving between the source reservoir 606 and the storage reservoir 610.

In some examples, the interiors of the storage reservoir 610 and source reservoir 606 may be substantially fluidly isolated from each other, such that neither gas nor liquid can easily/freely pass between reservoirs 606 and 610. Alternatively, as illustrated in Figure, the interiors of the storage reservoir 610 and source reservoir 606 may be in gas flow communication with each other, such as by providing the gas exchange passage 626 that can connect the layer of cover gas 602 with a layer of cover gas 608 in the source reservoir 606. The gas exchange passage 626 can be configured to allow free, two-way flow of gas between the storage reservoir 610 and the source reservoir 606 or may be configured to only allow one-way gas flow (in either direction). Providing a free flow of gas between the storage reservoir 610 and the source reservoir 606 may help automatically match the pressures within the storage reservoir 610 and the source reservoir 606. Preferably, when arranged in this manner, the interior of the storage reservoir 610 remains at least partially isolated from the interior of the source reservoir 606 during normal operation to inhibit, and preferably prevent mixing of the relatively hot cover gas associated with the thermal storage liquid 600 in the storage reservoir 610 with the relatively cooler cover gas associated with the thermal storage liquid in the source reservoir 606. In this example, the storage reservoir 610 and source reservoir 606 share a common sidewall, which can function as an isolating barrier 625 to prevent liquid mixing between the reservoirs. This common sidewall may be insulated to prevent unwanted heat transfer from the relatively hot thermal storage liquid 600 in the storage reservoir 610 to the relatively cooler thermal storage liquid in the source reservoir 606.

Optionally, the thermal storage reservoir 610 may be located above ground, and may be comprised of purpose built vessels.

When the compressed gas energy storage systems are in a charging mode, compressed gas is being directed into the accumulator 12 and the thermal storage liquid 600 can be drawn from the thermal storage liquid source 605, passed through one side of a suitable heat exchanger 635 (including one or more heat exchanger stages) to receive thermal energy from the compressed gas stream exiting the compressor/expander subsystem 100, and then conveyed/ pumped through the liquid inlet/outlet passage 630 and into the storage reservoir 610 for storage at the storage pressure.

When the compressed gas energy storage system is in a storage mode, compressed gas is neither flowing into or out of the accumulator 12 or thorough the heat exchanger 635, and the thermal storage liquid 600 need not be circulated through the heat exchanger 635.

When the compressed gas energy storage systems are in a discharging mode, compressed gas is being transferred from the accumulator 12 and into the compressor/expander subsystem 120 for expansion and the thermal storage liquid 600 can be drawn from the storage reservoir 610, passed through one side of a suitable heat exchanger 635 (including one or more heat exchanger stages) to transfer thermal energy from thermal storage liquid into the compressed gas stream to help increase the temperature of the gas stream before it enters the compressor/expander subsystem 100. Optionally, the thermal storage fluid can then be conveyed/ pumped into the source reservoir 606 for storage.

The thermal storage liquid 600 can be conveyed through the various portions of the thermal storage subsystem 120 using any suitable combination of pumps, valves, flow control mechanisms and the like. Optionally, an extraction pump may be provided in fluid communication with, and optionally at least partially nested within, the storage reservoir 610 to help pump the thermal storage liquid 600 from the storage reservoir 610 up to the surface. Such a pump may be a submersible type pump and/or may be configured so that the pump and its driving motor are both located within the storage reservoir 610. Alternatively, the pump may be configured as a progressive cavity pump having a stator and rotor assembly 668 (including a rotor rotatably received within a stator) provided in the storage reservoir 610 and positioned to be at least partially submerged in the thermal storage liquid 600, a motor 670 that is spaced from the stator and rotor assembly 668 (on the surface in this example) and a drive shaft 672 extending therebetween. In this example, the drive shaft 672 is nested within the liquid inlet/outlet passage 630 extending to the storage reservoir 610, but alternatively may be in other locations.

Optionally, the storage reservoir 610 may at least partially be pressurized by allowing the heated thermal storage liquid within the thermal storage reservoir to partially vaporize and in turn pressurize the cover gas layer 602 of the thermal storage reservoir until an equilibrium has been reached where the pressure of the cover gas layer 602 is approximately equal to the boiling pressure of the thermal storage liquid within the thermal storage reservoir 610.

FIG. 4 is a schematic view of components of on example of a compressor/expander subsystem for use with a suitable compressed gas energy storage system (including the hydrostatically compensated systems described herein and other systems that are not hydrostatically compensated), with pairs of compression and expansion stages each associated with a respective heat exchanger of the thermal storage subsystem 120.

In this embodiment, a given exchanger of the thermal storage subsystem 120 is used during both the compression and expansion stages, by routing air being conveyed into the accumulator 12 through the thermal storage subsystem 120 to remove heat from the air following a stage of compression, and routing air being conveyed out of accumulator 12 through the thermal storage subsystem 120 to add heat to the air prior to a stage of expansion. In a sense, therefore, pairs of compression and expansion stages share a heat exchanger 635 a, 635 b and 635 x and airflow is controlled using valves V, as shown in FIG. 4 . This embodiment may be useful where the “same” heat/ thermal energy received from the compressed air being conveyed through the air flow path towards the accumulator 12 during a storage phase is intended to be reintroduced and/or transferred into the air being released from the accumulator 12 during a release phase.

The embodiment of FIG. 4 has a first heat exchanger 635 a provided in the gas flow path and operable to transfer thermal energy between the compressed gas travelling through the gas flow path and the thermal storage liquid. A further second heat exchanger 635 b is provided in the gas flow path downstream from the first heat exchanger and operable to transfer thermal energy between the compressed gas travelling through the gas flow path and the thermal storage liquid. For clarity, downstream refers to the path of compressed gas in charging mode. A further third heat exchanger 635 x is provided in the gas flow path downstream from the second heat exchanger and operable to transfer thermal energy between the compressed gas travelling through the gas flow path and the thermal storage liquid.

Usage of multiple heat exchangers may allow the system to operate under desirable conditions. Since there are multiple stages of heat exchangers in this arrangement, no single heat exchanger needs to be responsible for capturing all the thermal energy from the compressed gas. Instead, there are multiple opportunities for the thermal energy in the compressed gas to be transferred to the thermal storage media. The thermal storage media can therefore be kept at a lower temperature, which may reduce the pressure to which the thermal storage liquid needs to be pressurized to maintain its liquid state, may optionally eliminate the need to pressurize the thermal storage liquid generally above atmospheric pressure and/or may help reduce the need for thermal insulative material in the thermal storage reservoir or other portions of the thermal storage subsystem 120.

Similarly, in the discharging mode, thermal energy may be transferred to the gas exiting the accumulator from the thermal storage media at each of the heat exchangers. The additional heat exchangers may help improve the overall efficiency of the thermal energy transfer back to the gas, as well as help each expansion stage have an inlet temperature which is close to its designed operating inlet temperature.

FIG. 5 is a schematic view of components of the alternative example of a compressor/expander subsystem, showing airflow during an expansion (discharging) phase from storage through multiple expander stages and multiple respective heat exchangers of the thermal storage subsystem 120. In this phase, through control of valves V, airflow is directed through multiple stages of expansion. The dashed lines show multiple compression stages the airflow to which is prevented during an expansion phase by the control of valves V.

FIG. 6 is a schematic view of components of the alternative compressor/expander subsystem of FIG. 4 , showing airflow during a compression (charging) phase from the ambient A through multiple compressor stages and multiple respective heat exchangers of the thermal storage subsystem 120. In this phase, through control of valves V, airflow is directed through multiple compression stages. The dashed lines show multiple expansion stages the airflow to which is prevented during the compression phase by the control of valves V.

FIG. 7 is a sectional view of components of an alternative compressed gas energy storage system 10C, according to an embodiment. In this embodiment, compressed gas energy storage system 10C is similar to the other embodiments of the compressed gas energy storage systems described herein. However, in this embodiment the thermal storage subsystem 120 (including any of the suitable variations described herein, including a storage reservoir 610, source reservoir 606 and related equipment) is located within the accumulator 12 and may be at least partially immersed within the compressed gas in compressed gas layer 14. The thermal storage subsystem 120 may be positioned within the accumulator 12 during construction via the opening 27 that is thereafter blocked with bulkhead 24 prior to filling shaft 18 with liquid 20. The thermal storage subsystem 120 can thus be designed to allow for the construction, insulation, etc. to be completed prior to placement within the accumulator 12 and/or is constructed in easily-assembled components within the accumulator 12. This allows for the units to be highly insulated and quality-controlled in their construction, which enables the thermal storage subsystem 120 to be generally independent of the accumulator 12, with the exception of an anchoring support (not shown).

Optionally, a regulating valve 130 associated with the interior of thermal storage subsystem 120 may be provided and configured to open should the pressure within the thermal storage subsystem 120 become greater than the designed pressure-differential between its interior and the pressure of the compressed gas layer 14 in the surrounding accumulator 12. Pressure within the thermal storage subsystem 120 may be maintained at a particular level for preferred operation of the latent or sensible material. For example, heated water as a sensible material may be maintained at a particular pressure to maintain the thermal fluid in its liquid state at the storage temperature. The regulating valve 130 may open to allow the pressurized gas in the interior to escape to the accumulator 12 and can close once the pressure differential is lowered enough to reach a designated level. In an alternative embodiment, such a regulating valve may provide fluid communication between the interior of the thermal storage subsystem 120 and the ambient A at the surface thereby to allow gas to escape to the ambient rather than into the accumulator 12. While thermal storage subsystem 120 is shown entirely immersed in the compressed gas layer 14, alternative thermal storage subsystems 120 may be configured to be immersed partly or entirely within liquid layer 16. In some examples, only a portion of the thermal storage subsystem 120, such as the storage reservoir 610, may be at least partially nested within the accumulator 12, and other portions, such as the heat exchangers and the source reservoir 606, may be spaced apart from the accumulator 12.

FIG. 8 is a sectional view of components of an alternative compressed gas energy storage system 10D, according to another alternative embodiment. In this embodiment, the compressed energy gas storage system 10D includes a different type of accumulator 12D that is not hydrostatically compensated, and may be a salt cavern, an existing geological formation, or manmade cavern. That is, the accumulator 12D is configured to contain compressed gas but need not include a liquid layer or be associated with a shaft containing water. This is another type of accumulator that may, in some embodiments, be used in place of or in addition to the accumulators 12 used with respect to other embodiments of the compressed gas energy storage systems described herein. Aspects of the thermal storage subsystems 120 described in this embodiment may be used in combination with the hydrostatically compensated compressed gas energy storage systems described, and aspects of the thermal storage subsystems 120 depicted in other embodiments may be utilized with accumulators similar to accumulator 12D. In this embodiment, compressed gas energy storage system 10D is similar to above-described compressed gas energy storage systems. However, the thermal storage subsystem 120 is located within an isobaric pressurized chamber 140 within ground 200 that may be maintained at the same pressure as is accumulator 12, or a pressure that is substantially similar to the accumulator pressure or optionally at a pressure that is less than or greater than the accumulator pressure. Optionally, the thermal storage subsystem 120 may be positioned within the pressurized chamber 140 during construction via an opening that is thereafter blocked so the chamber 140 may be pressurized to a working pressure that is, preferably, greater than atmospheric pressure. The thermal storage subsystem 120 can thus be designed to allow for the construction, insulation, etc. to be completed prior to placement within the chamber 140 and/or is constructed in easily-assembled components within the chamber 140. This allows for the units to be highly insulated and quality-controlled in their construction, which enables the thermal storage subsystem 120 to be generally independent of the chamber 140, with the exception of anchoring support (not shown). A regulating valve 130 associated with the interior of thermal storage subsystem 120 is provided and configured to open should the pressure within the thermal storage subsystem 120 become greater than the designed pressure-differential between the interior and the surrounding pressurized chamber 140. Pressure within the thermal storage subsystem 120 may be required to be maintained at a particular level for optimal operation of the latent or sensible material. For example, heated water as a sensible material may be required to be maintained at a particular pressure to maintain the thermal fluid in its liquid state at the storage temperature. The regulating valve 130 opens to allow the pressurized gas in the interior to escape to the pressurized chamber 140 and closes once the pressure differential is lowered enough to reach a designated level. In an alternative embodiment, such a regulating valve 130 may provide fluid communication between the interior of the thermal storage subsystem 120 and the ambient A at the surface thereby to allow gas to escape to the ambient rather than into the pressurized chamber 140.

Locating the thermal storage subsystem 120 above the accumulator 12, and thus physically closer to the compression/expansion subsystem 100, may help reduce the length of piping required, which may help reduce the costs of piping, installation and maintenance, as well as reduced fluid-transfer power requirements.

While the embodiment of compressed gas energy storage system 10D includes an isobaric pressurized chamber 140, alternatives are possible in which the chamber 140 is not strictly isobaric. Furthermore, in alternative embodiments the pressurized chamber 140 may be in fluid communication with gas layer 14 and thus can serve as a storage area for compressed gas being compressed by compressor/expander subsystem 100 along with accumulator 12. In this way, the pressure of the gas in which the thermal storage subsystem 120 is immersed can be maintained through the same expansions and compressions of gas being conveyed to and from the accumulator 12.

Optionally, compressed gas energy storage system 10D may include a thermal storage system which is not located in an underground pressurized chamber, and may be located above the ground surface.

Optionally, any of the thermal storage subsystems 120 described herein may include a thermal conditioning system that can be used to regulate the temperature of the layer of cover gas 602 in the storage reservoir 610 and/or in the source reservoir 606. For example, the thermal conditioning system may include a fan cooler, heat exchanger, evaporator coils or other such equipment so that it can be used to optionally reduce (or alternatively increase) the temperature of the layer of cover gas 602 when the thermal storage subsystem 120 is in use.

In certain preferred embodiments, the compression/expander subsystem 100 for use with a suitable compressed gas energy storage system may include three compression/expansion stages or more, each associated with a respective heat exchanger of the thermal storage subsystem 120.

Referring to FIG. 9 , another example of a thermal storage subsystem 1120 for use with any of the systems 10 described herein is illustrated. The thermal storage subsystem 1120 is analogous to the thermal storage subsystem 120 and like features are annotated using like reference characters indexed by 1000.

This embodiment of the thermal storage subsystem 1120 includes a heat exchanger assembly 1635 that includes three heat exchangers 1635 a, 1635 b and 1635 c, although embodiments of three or more exchangers would also exhibit the beneficial characteristics of this invention. This thermal storage subsystem 1120 is configured to be used in combination with any suitable compression and expansion subsystem 100 that includes three (or more) compression and expansion stages, including those described herein. The thermal storage subsystem 1120 also includes a source reservoir 1606 for holding a supply of relatively cool thermal storage fluid (water in this embodiment) at a source temperature and source pressure and an associated storage reservoir 1610 for containing relatively warmer thermal storage fluid at a thermal storage temperature that is higher than the source temperature and thermal storage pressure that may optionally be higher than the source pressure and may be higher than atmospheric pressure.

Optionally, it may be desirable to operate the thermal storage system 1120 such that the heated fluid that is contained in the storage reservoir 1610 is heated to a storage temperature that is greater than the vapour temperature/ boiling point of the liquid (i.e. water) at atmospheric pressure. To help maintain the fluid in its liquid state, at least some portions the thermal storage system 1120, such as the storage reservoir 1610 and conduits connected thereto, are preferably pressurized to a pressure that is greater than atmospheric pressure and is sufficient to inhibit boiling of the thermal storage fluid/ water when at the storage temperature.

Preferably, the compressor/expander subsystem 100 and the thermal storage subsystem 1120 are collectively configured so that the gas pressure at the outlet of the compressor/expander subsystem 100 is the same as the pressure of the compressed gas within the accumulator 12 and that the cover gas pressure in thermal storage reservoir 1610 is greater than the vapour pressure of the water contained within the storage reservoir 1610 at its storage temperature.

Although the desired thermal storage temperature may vary depending on the choice of thermal storage liquid and its vapour pressure at the thermal storage temperature, the thermal storage temperature may be, in some examples, between about 150° C. and about 350° C., and may be between about 175 and about 300° C., and between about 200 and 275° C. This lower and upper limit on the thermal storage liquid is with regard to feasibility of the system, as lower temperatures may have a significant impact on the amount of thermal energy that can be stored while higher temperatures may be difficult to maintain with regards to thermal insulation and conductivity.

Referring again to FIG. 9 , in this embodiment, the first stage of the compression/expansion subsystem 100 may include a first compressor 112 a and a first expander 116 a. The thermal storage subsystem 1120 includes, in this embodiment, a corresponding heat exchanger 1635 a that may be used during both the compression and expansion stages of the first compressor 112 a and first expander 116 a. The second stage of compression/expansion may include a second compressor 112 b and a second expander 116 b. The thermal storage subsystem 1120 includes, in this embodiment, a corresponding second heat exchanger 1635 b that may be used during both the compression and expansion stages of the second compressor 112 b and second expander 116 b. The third stage of compression/expansion may include a third compressor 112 c and a third expander 116 c. The thermal storage subsystem 1120 includes, in this embodiment, a corresponding third heat exchanger 1635 c which may be used during both the compression and expansion stages of the third compressor 112 c and third expander 116 c. Embodiments of three or more exchangers would also exhibit the beneficial characteristics of this invention.

The three compression/expansion stages of this embodiment 112 a-112 c and corresponding heat exchangers 1635 a-1635 c may be arranged in sequence such that when the compression/expansion subsystem 100 (and the overall system 10) is operated in its expansion/charging mode air may move sequentially through the first compressor 112 a and first heat exchanger 635 a, to the second compressor 112 b and second heater exchanger 635 b, to the third compressor 112 c and third heat exchanger 635 c, then on to the accumulator 12.

Alternatively, when the compression/expansion subsystem 100 is in its discharging mode, air may be removed from the accumulator 12 and conveyed sequentially through the third heat exchanger 635 c and third expander 116 c, to the second heat exchanger 635 b and second expander 116 b, to the first heat exchanger 635 a and first expander 116 a.

As further shown in FIG. 9 , the thermal storage subsystem 1120 that is used with the compression/expansion subsystem 100 may include a cold fluid source reservoir 1606 that includes a tank 1703 and a hot fluid storage reservoir 1610 that includes a tank 1701. During compression/charging operations, relatively cooler thermal fluid 1704 from the cold fluid storage chamber 1703 may be directed through each of the three heat exchangers 1635 a, 1635 b, and 1635 c, where the relatively cooler thermal fluid will absorb heat/ thermal energy from the gas stream passing through each heat exchanger and the resulting, relatively warmer thermal fluid 1702 will be sent from the outlet of each heat exchanger 1635 a, 1635 b, and 1635 c to a common hot thermal fluid storage tank 1701. In a preferred embodiment, each of the three heat exchangers 1635 a, 1635 b, and 1635 c will be configured to operate under analogous conditions i.e., each heat exchanger may be configured to transfer about the same amount of heat to/from the thermal fluid passing through the exchanger. Configuring the heat exchangers 1635 a, 1635 b, and 1635 c to operate under analogous conditions may help facilitate an arrangement in which heat exchanger 1635 a, 1635 b, and 1635 c can be provided with incoming, relatively cool thermal fluid from a common thermal fluid source reservoir 1606 (i.e. tank 1703 and associated piping network) and may also help facilitate an arrangement in which the relatively warmer thermal fluid exiting each heat exchanger 1635 a, 1635 b, and 1635 c has been heated to substantially the same exit temperature, and can be collected via a common piping network and stored in a common storage reservoir 1610 (i.e. tank 1701). During discharging, this can also allow the relatively warm thermal fluid to be drawn from the common storage reservoir 1606 and supplied as the inlet fluid to the heat exchanger 1635 a, 1635 b, and 1635 c and used to re-warm the gas exiting the accumulator 12 prior to each stage of expansion the expansion (discharging) operating mode.

FIG. 10 is a schematic view of components of the three-stage compressor/expander subsystem with three corresponding heat exchangers of FIG. 9 , showing airflow and thermal fluid flow during a compression (charging) mode. In this mode, ambient air may be conveyed through the first compressor 112 a and then into the first heat exchanger 635 a with a specific set of gas inlet conditions at 1705.

In certain preferred embodiments the inlet gas pressure at 1705 may be around 2 - 5 bar and is around a third of the ratiometric pressure rise to the accumulator pressure (i.e. the accumulator pressure to the power of ⅓) and the inlet gas temperature may be at or around 150 - 300 C. As the gas with inlet conditions 1705 passes through the first heat exchanger 1635 a, relatively cooler fluid 1704 from the source reservoir 1703 may be passed through a liquid inlet of the first heat exchanger 1635 a and may interact, directly or indirectly, with the gas travelling between the first and second compression stages such that the gas transfers heat to the cold fluid 1704. The resulting warmer fluid 1702 will have a set of fluid outlet conditions at the liquid outlet 1711 of the first heat exchanger 1635 a and may then be transferred to a hot storage reservoir 1610.

Gas exiting the first heat exchanger 1635 a will also have a set of gas outlet conditions at the gas outlet of the 1706 such that the outlet gas pressure at 1706 is about the same as the gas inlet pressure at the gas inlet 1705, and the gas outlet temperature at the gas outlet 1706 is lower that the gas temperature at the gas inlet 1705 and may be between the ambient air temperature and about 50 C. Gas exiting the first heat exchanger 1635 a may then be conveyed through the second compressor 112 b and then into the second heat exchanger 1635 b with a set of gas inlet conditions at the second gas inlet 1707 to heat exchanger 1635 b. In certain preferred embodiments, as a result of further gas compression from the second compressor 112 b, the inlet gas pressure at the gas inlet 1707 may be around 11 - 18 bar and is around two-thirds of the ratiometric pressure rise to the accumulator pressure (i.e. the accumulator gauge pressure to the power of ⅔) and the inlet gas temperature at the gas inlet 1707 may be at or around 150 - 300 C. As the gas with conditions at gas inlet 1707 passes through the second heat exchanger 1635 b, cooler fluid from a source reservoir 1606 is provided via the second liquid inlet and can then be passed through the second heat exchanger 1635 b and interact, directly or indirectly with the gas such that the gas may transfer heat to the cooler fluid. The resulting warmer fluid will have a specific set of conditions (outlet temperature and outlet pressure) at the second liquid outlet 1712 and may then be transferred to a hot storage reservoir 1610. Preferably, conditions at the second liquid outlet 1712 of the second heat exchanger 1635 b will be at about the same as the conditions at the liquid outlet 1711 of the first heat exchanger 1635 a.

Gas exiting the gas outlet 1708 of the second heat exchanger 1635 b will have specific set of gas outlet conditions such that the outlet gas pressure at the outlet 1708 is about the same as the pressure at the gas inlet 1707, and the temperature at the gas outlet 1708 is lower that the temperature at the gas inlet 1707 and may be between the ambient air temperature and about 50 C. Gas exiting the second heat exchanger 1635 b may then be conveyed through the third compressor 112 c and then into the third heat exchanger 1635 c with a specific set of conditions at the third gas inlet 1709. In certain preferred embodiments, as a result of further gas compression from the third compressor 112 c, the pressure at the gas inlet 1709 may be at or around the magnitude of the desired storage pressure of pressurized gas in the accumulator 12 and the temperature at the gas inlet 1709 may be at or around 150 - 300 C.

As the gas moves from the gas inlet 1709 and passes through the third heat exchanger 1635 c, cooler fluid 1704 from the source reservoir 1606 may be passed through the third heat exchanger 1635 c and interact, directly or indirectly with the gas such that the gas may transfer heat to the cooler fluid 1704. The resulting warmer fluid 1702 will have a set of conditions at the third liquid outlet 1713 and may then be transferred to a hot storage reservoir 1610. Preferably, the warmer fluid 1702 at the liquid outlet 1713 of the third heat exchanger 1635 c will be at about the same temperature as the warmer fluid 1702 at the liquid outlets 1711 and 1712 of the first and second heat exchangers, 1635 a and 1635 b, respectively.

Gas exiting the third heat exchanger, via its gas outlet 1710 will have specific set of gas outlet conditions such that the outlet gas pressure is about the same pressure as the desired storage pressure of pressurized gas in the accumulator 12, and the gas outlet temperature at 1710 is lower than the gas inlet temperature at inlet 1709 and be between the ambient air temperature and about 50 C. Gas exiting the third heat exchanger 1635 c may then be conveyed to the accumulator 12.

FIG. 11 is a schematic view of components of the three-stage compressor/expander subsystem with three corresponding heat exchangers 1635 a, 1635 b and 1635 c of FIG. 9 , showing airflow and thermal fluid flow during an expansion (discharging) mode from storage through multiple expander stages and multiple respective heat exchangers of the thermal storage subsystem.

In this discharging mode, air may be conveyed from the accumulator 12 to the third heat exchanger 1635 c with a specific set of conditions at the discharge mode gas inlet 1714 (which is the gas outlet when in the charging mode). As the gas passes through the third heat exchanger 1635 c, relatively warmer thermal fluid 1702 from a thermal storage reservoir 1610 enters the third heat exchanger 1635 c via the discharge liquid inlet 1720 and has an inlet temperature and may be passed through the third heat exchanger 1635 c and interact, directly or indirectly with the gas such that the relatively warmer thermal fluid transfers heat to the gas as it travels through the third heat exchanger 1635 c and before it enters the third expander 116 c. The resulting cooler fluid 1704 may then exit the third heat exchanger 1635 c and be transferred to a source reservoir 1606. By way of non-limiting example, the temperature of relatively warmer thermal fluid at fluid inlet 1720 may be about equal to the temperature of thermal fluid in the thermal storage reservoir 1610.

Gas exiting the third exchanger 1635 c when in the discharge mode will have set of conditions at gas outlet 1715 such that the outlet gas pressure at 1715 is about the same as the gas inlet pressure at 1714 and the gas outlet temperature at 1715 is higher than the gas inlet temperature at 1714 and as near to the fluid storage temperature as the heat exchangers will facilitate, preferably within 5 - 25° C. or less. Gas exiting the third heat exchanger 1635 c may then be conveyed through the third expander 116 c and then into the second heat exchanger 1635 b with a specific set of conditions at discharge gas inlet 1716. In certain preferred embodiments gas exiting the first expander 116 c may have a resulting pressure at 1716 of around 11 - 18 bar and is around a third of the ratiometric pressure reduction from the accumulator pressure to ambient pressure (i.e. the accumulator gauge pressure to the power of ⅔) and an inlet gas temperature at 1716 of around 30 - 70 C.

As the gas passes from inlet 1716 through the second heat exchanger 1635 b, relatively warmer thermal fluid 1702 from a storage reservoir 1610 can enter via warm liquid inlet 1721 may be passed through the second heat exchanger 1635 b and interact, directly or indirectly with the gas such that the warmer fluid 1702 transfers heat to the gas. The resulting cooler fluid 1704 may then be transferred to a cold source reservoir 1606. By way of non-limiting example, the temperature of the liquid entering via the liquid inlet 1721 may be about equal to the temperature of thermal fluid in the thermal storage reservoir 1610.

Gas exiting the second heat exchanger 1635 b will have specific set of conditions at discharging gas outlet 1717 such that the outlet gas pressure at 1717 is about the same as the gas inlet pressure at 1716 and the gas outlet temperature at 1717 is higher than the gas inlet temperature at 1716 and as near to the fluid storage temperature as the heat exchangers will facilitate, preferably within 5 - 25° C. or less. Gas exiting the second heat exchanger 1635 b may then be conveyed through the second expander 116 b and then into the first heat exchanger 1635 a with a set of inlet conditions at liquid inlet 1718. In certain preferred embodiments gas exiting the second expander 116 b may have a resulting pressure at 1718 of around 2 - 5 bar and is around two-thirds of the ratiometric pressure reduction from the accumulator pressure to ambient pressure (i.e. the accumulator gauge pressure to the power of ⅓) and an inlet gas temperature at 1718 of around 30 - 70 C or lower.

As the gas flows from the inlet 1718 through the first heat exchanger 1635 a, relatively warmer thermal fluid 1702 from the storage reservoir 1610 can enter via liquid inlet 1722 having inlet conditions and may be passed through the first heat exchanger 1635 a to interact with, directly or indirectly with the gas such that the relatively warmer thermal fluid 1702 transfers heat to the gas. The resulting cooler fluid 1704 may then be transferred to the source reservoir 1606. By way of non-limiting example, the fluid inlet temperature of warmer liquid at 1722 may be about equal to the temperature of thermal fluid in the thermal storage reservoir 1610.

Gas exiting the first heat exchanger 1635 a, via gas outlet 1719 will have outlet conditions such that the outlet gas pressure at 1719 is at or about the same as the gas inlet pressure 1718, and the gas outlet temperature at 1719 is higher than the gas inlet temperature at 1718 and is as near to the fluid storage temperature as the heat exchangers will facilitate, preferably within 5 - 25° C. or less. The gas may then be routed to the first expander 116 a.

While illustrated as above ground tanks/ containers, one or both of the source reservoir 1606 and storage reservoir 1610 may be located underground (or at least partially underground) and may have different, physical arrangements. For example, one or both of the source reservoir 1606 and storage reservoir 1610 may be configured to include caverns (lined or unlined) and/or may be provided by repurposed parts of the system 10 that can be adapted to hold pressurized water at the desired storage temperature and pressure.

While in the embodiment of FIGS. 9-11 the compressors 112 and expanders 116 are shown as separate devices, in other embodiments the system 10 may include combined apparatuses that can function in both compressor and expander modes if suitable.

In a typical thermal storage system, heat exchangers may be optimized to allow flow of a first substance in one direction and flow of a second substance in the opposite direction, such that when the two substances cross paths (either directly or indirectly) heat and energy is transferred from the warmer substance to the cooler substance. Heat exchangers may typically be designed to operate only in one direction, that is the first substance always flows in one direction, while the second substance always flows in the opposite direction, and there is always a transfer of heat in the same direction from one substance to the other (e.g. from the first substance to the second substance). In certain preferred embodiments of the compressed gas energy storage system disclosed herein however, the thermal storage subsystem 120 may include one or more heat exchangers which are configured to be reversible, such that the first substance and second substance might flow in opposite directions within the heat exchanger depending on the operational state of compressed gas energy storage system. Furthermore, the reversible heat exchanger may be configured to transfer thermal energy from in both directions (i.e. from the first substance to the second substance and from the second substance to the first substance), depending on the operational state of compressed gas energy storage system. Configuring the same heat exchanger to be useable during both a charging and discharging modes may help lower overall costs and footprint for a compressed gas energy storage system.

In order to operate as reversible heat exchangers, the heat exchangers of the thermal storage subsystem 120 may be designed to accommodate a number of objectives. Each of the one or more reversible heat exchangers may for example be designed to meet inlet and outlet operational objectives (e.g., temperatures, pressures) for both the gas flow path and the thermal storage liquid flow path for flow in both operational modes (charging and discharging). To accomplish this, each of the one or more reversible heat exchangers may be designed to have two flow paths which pass through each reversible heat exchanger, a gas flow path and a liquid flow path. Each reversible heat exchanger may be designed as a counterflow heat exchanger, such that the gas flow path and liquid flow path are designed to flow in opposite directions from one another and to contact one another (either directly or indirectly) during one or more operational modes of the compressed gas energy storage system. For example, during a charging mode, the gas flow path may be configured to flow through one or more reversible heat exchangers in a gas charging flow direction, and the liquid flow path may be configured to flow through one or more reversible heat exchangers in a liquid charging flow direction, where the liquid charging flow direction is the opposite of the gas charging flow direction. During a discharging mode, the gas flow path may be configured to flow through one or more reversible heat exchangers in a gas discharging flow direction (which is the opposite direction of the gas charging flow direction), and the liquid flow path may be configured to flow through one or more reversible heat exchangers in a liquid discharging flow direction (which is the opposite direction of the liquid charging flow direction) , where the liquid discharging flow direction is the opposite of the gas discharging flow direction.

Referring to FIG. 12 , one example of a thermal storage subsystem 2120 which includes one or more reversible heat exchangers is illustrated during charging mode. The thermal storage system 2120 may by configured for use with any of the systems 10 described herein. The thermal storage subsystem 2120 is analogous to the thermal storage subsystem 120 described for other systems 10 herein and like features are annotated using like reference characters indexed by 2000.

This embodiment of the thermal storage subsystem 2120 includes a reversible heat exchanger assembly 2635 that includes three reversible heat exchangers 2635 a, 2635 b and 2635 c, although embodiments of three or more exchangers would also exhibit the beneficial characteristics of this invention. This thermal storage subsystem 2120 is configured to be used in combination with any suitable compression and expansion subsystem 100 that includes three (or more) compression and expansion stages, including those described herein. The thermal storage subsystem 2120 also includes a source reservoir 2606 for holding a supply of relatively cool thermal storage fluid (water in this embodiment) at a source temperature and source pressure and an associated thermal storage reservoir 2610 for containing relatively warmer thermal storage fluid at a thermal storage temperature that is higher than the source temperature and thermal storage pressure that may optionally be higher than the source pressure and may be higher than atmospheric pressure. In certain embodiments, the thermal storage reservoir 2610 may be configured to be at least partially underground.

As illustrated in FIG. 12 , during charging mode, a stream of compressed gas may be directed from one or more compressors of the gas compressor/expander subsystem 100 toward the accumulator 12, whereby the compressed gas is directed through a first gas flow path in a gas charging flow direction (indicated by flow arrows 2800), and a thermal storage liquid may directed through the first liquid flow path in a liquid charging flow direction (indicated by flow arrows 2810) from a thermal source reservoir 2606 toward a thermal storage reservoir 2610 whereby thermal energy is transferred from the compressed gas into the thermal storage liquid within one or more reversible heat exchangers 2635 a-c. In certain preferred embodiments, the gas charging flow direction 2800 and the liquid charging flow direction 2810 may be opposite from one another inside the one or more reversible heat exchangers 2635 a-c, in order to allow the most efficient heat transfer form the compressed gas to the thermal storage liquid within each reversible heat exchanger 2635 a-c. The thermal storage subsystem 2120 as shown in FIG. 12 comprises three reversible heat exchangers, however other embodiments may include three or more reversible heat exchangers. Further, while each heat exchanger 2635 is shown in FIG. 12 to have only one module (or shell), there may be other embodiments where each reversible heat exchanger 2635 has at least a first and second exchanger module (or shell) arranged in fluid communication in series and/or parallel with each other.

During charging mode, compressed gas may be directed through a first compression stage 2112 a through the flow path in the gas charging flow direction (indicated by flow arrows 2800) and into the first reversible heat exchanger 2635 a. The first reversible heat exchanger 2635 a may be configured such that compressed gas entering the first reversible heat exchanger 2635 a at gas inlet point 2705 may be within a certain number of degrees, in this embodiment 5 - 25 deg C or less, of the outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger 2635 a at liquid outlet point 2711. To accomplish this, it may be desirable to operate the system such that the gas entering the first reversible heat exchanger 2635 a at gas inlet point 2705 from a first compression stage 2112 a may have a particular set of operating parameters. For example, the gas at inlet point 2705 may have a temperature of between about 190-250° C., or preferably between about 195-210° C.

, or more preferably between about 198-205° C. In certain preferred embodiments the gas inlet point 2705 may have a pressure around 2 - 5 bar and is around a third of the ratiometric pressure rise to the accumulator pressure (i.e. the accumulator gauge pressure to the power of ⅓). Similarly, the thermal storage liquid entering the first reversible heat exchanger 2635 a at liquid inlet point 2730 may have a particular set of operating parameters. For example, the thermal storage liquid at liquid inlet point 2730 may have a temperature of between about 20 to 50° C., or preferably between about 30-40° C., or more preferably about 35° C. The thermal storage liquid at inlet point 2730 may be at or around atmospheric pressure.

With these optimal operating parameters in mind, the first reversible heat exchanger 2635 a may be designed so that when in charging mode, the inlet temperature of the compressed gas entering the first reversible heat exchanger 2635 a at gas inlet point 2705 may be within about 25 degrees or less of the outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger 2635 a at liquid outlet point 2711 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 12 , if the inlet temperature of compressed gas entering the first reversible heat exchanger 2635 a at gas inlet point 2705 is 202° C., the first reversible heat exchanger 2635 a may be configured such that the outlet temperature of thermal storage liquid exiting the first reversible heat exchanger at liquid outlet point 2711 is around about 180 - 198° C. Where a three-stage compression system is used, such as that shown in FIGS. 9-13 , the pressure of the compressed gas exiting the first reversible heat exchanger at gas outlet point 2706 may be around about third of the radiometric pressure rise to the accumulator pressure (i.e. the accumulator gauge pressure to the power of ⅓

After exiting the first reversible heat exchanger 2635 a, the compressed gas may be directed to through a second compression stage 2112 b through the gas flow path in a gas charging flow direction (indicated by flow arrows 2800), and thermal storage liquid may be directed through the liquid flow path in a liquid charging flow direction (indicated by flow arrows 2810) toward a thermal storage reservoir 2610.

In certain preferred embodiments, that gas charging flow direction 2800 and the liquid charging flow direction 2810 may be opposite from on another when inside the first reversible heat exchanger, in order to allow the most efficient heat transfer form the compressed gas to the thermal storage liquid within the first reversible heat exchanger 2635 a.

During charging mode, the second reversible heat exchanger 2635 b may be configured such that compressed gas entering the second reversible heat exchanger 2635 b at gas inlet point 2707 after a second compression stage may be within a certain number of degrees of the outlet temperature of the thermal storage liquid exiting the second reversible heat exchanger 2635 b at liquid outlet point 2712. To accomplish this, it may be desirable to operate the system such that the gas entering the second reversible heat exchanger 2635 b at gas inlet point 2707 from a second compression stage 2112 b may have a particular set of operating parameters. For example, the gas at gas inlet point 2707 may have a temperature of between about 190-250° C., or preferably between about 195-210° C., or more preferably between about 195-205° C. In certain preferred embodiments gas inlet point 2707 may have a pressure of around 11 - 18 bar and is around two thirds of the ratiometric pressure rise to the accumulator pressure from ambient pressure (i.e. the accumulator gauge pressure to the power of ⅔). Similarly, the thermal storage liquid entering the second reversible heat exchanger 2635 b at liquid inlet point 2731 may have a particular set of operating parameters. For example, the thermal storage liquid at liquid inlet point 2731 may have a temperature of between about 20 to 50° C., or preferably between about 30-40° C., or more preferably about 35° C. The thermal storage liquid at inlet point 2730 may be at or around atmospheric pressure.

With these optimal operating parameters in mind, the second reversible heat exchanger 2635 b may be designed so that when in charging mode, the inlet temperature of the compressed gas entering the second reversible heat exchanger 2635 b at inlet point 2707 may be within about 25 degrees of the outlet temperature of the thermal storage liquid exiting the second reversible heat exchanger 2635 b at liquid outlet point 2712 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 12 , if the inlet temperature of compressed gas entering the second reversible heat exchanger 2635 b at gas inlet point 2707 is 201° C., the second reversible heat exchanger 2635 b may be configured such that the outlet temperature of thermal storage liquid exiting the second reversible heat exchanger at exit point 2712 is around about 180-199° C. Where a three-stage compression system is used, such as that shown in FIGS. 9-13 , the pressure of the compressed gas exiting the second reversible heat exchanger at gas outlet point 2708 may be around about two thirds of the ratiometric pressure rise to the accumulator pressure (i.e. the accumulator gauge pressure to the power of ⅔).

After exiting the second reversible heat exchanger 2635 b, the compressed gas may be directed to through a third compression stage 2112 c via the gas flow path in a gas charging flow direction (indicated by flow arrows 2800), and thermal storage liquid may be directed through the liquid flow path in a liquid charging flow direction (indicated by flow arrows 2810) toward a thermal storage reservoir 2610.

In certain preferred embodiments, that gas charging flow direction 2800 and the liquid charging flow direction 2810 may be opposite from on another when inside the second reversible heat exchanger, in order to allow the most efficient heat transfer form the compressed gas to the thermal storage liquid within the second reversible heat exchanger 2635 b.

During charging mode, the third reversible heat exchanger 2635 c may be configured such that compressed gas entering the third reversible heat exchanger 2635 c at gas inlet point 2709 may be within a certain number of degrees of the outlet temperature of the thermal storage liquid exiting the second reversible heat exchanger 2635 c at liquid outlet point 2713. To accomplish this, it may be desirable to operate the system such that the gas entering the third reversible heat exchanger 2635 c at gas inlet point 2709 from a second compression stage 2112 c may have a particular set of operating parameters. For example, the gas at inlet point 2709 may have a temperature of between about 190-250° C., or preferably between about 195-210° C., or more preferably between about 195-205° C. In certain preferred embodiments gas inlet point 2709 may have a pressure of around 35 - 75 bar and is approximately equal to the storage pressure of the accumulator 12. Similarly, the thermal storage liquid entering the third reversible heat exchanger 2635 c at liquid inlet point 2732 may have a particular set of operating parameters. For example, the thermal storage liquid at inlet point 2732 may have a temperature of between about 20 to 50° C., or preferably between about 30-40° C., or more preferably about 35° C. The thermal storage liquid at inlet point 2730 may be at or around atmospheric pressure With these optimal operating parameters in mind, the third reversible heat exchanger 2635 c may be designed so that when the system is in charging mode, the inlet temperature of the compressed gas entering the third reversible heat exchanger 2635 c at inlet point 2709 may be within about 25 degrees of the outlet temperature of the thermal storage liquid exiting the third reversible heat exchanger 2635 c at liquid outlet point 2713 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 12 , if the inlet temperature of compressed gas entering the third reversible heat exchanger 2635 c at gas inlet point 2709 is 202° C., the third reversible heat exchanger 2635 c may be configured such that the outlet temperature of thermal storage liquid exiting the second reversible heat exchanger at exit point 2713 is around about 180199° C. Where a three-stage compression system is used, such as that shown in FIGS. 9-13 , the pressure of the compressed gas exiting the third reversible heat exchanger at gas outlet point 2710 may be around about the desired storage pressure for the accumulator 12.

Referring to FIG. 13 , the thermal storage system of FIG. 12 is shown in discharging mode. As illustrated in FIG. 13 , during discharging mode, a stream of compressed gas from the accumulator 12 may be directed toward the gas compressor/expander subsystem 100, whereby the compressed gas is redirected through the gas flow path in a gas discharging flow direction (shown by gas flow arrows 2820) that is opposite the charging gas direction and the thermal storage liquid is redirected through the liquid flow path in a liquid discharging flow direction (shown by liquid flow arrows 2830) that is opposite the liquid charging flow direction from the thermal storage reservoir 2610 toward the thermal source reservoir 2606 whereby at least a portion of the thermal energy in the thermal storage liquid is returned into the compressed gas within one or more reversible heat exchangers 2635 a-c. In certain preferred embodiments, the gas discharging flow direction 2820 and the liquid discharging flow direction 2830 may be opposite from one another when inside of reversible heat exchangers 2635 a-c, in order to allow the most efficient heat transfer form the thermal storage liquid to the compressed gas within each reversible heat exchanger 2635 a-c. The system as shown in FIG. 13 comprises three reversible heat exchangers, however other embodiments may three or more reversible heat exchangers. Further, while each heat exchanger 2635 a-c is shown in FIG. 13 to have only one heat exchanger module, there may be other embodiments where each reversible heat exchanger 2635 a-c has at least a first a second exchanger module arranged in fluid communication in series and/or parallel with each other.

During the discharging mode, compressed gas may be directed through the gas flow path in the gas discharging flow direction (indicated by flow arrows 2820) and from the accumulator into the third reversible heat exchanger 2635 c. The third reversible heat exchanger 2635 c may be configured such that thermal storage liquid entering the third reversible heat exchanger 2635 c at liquid inlet point 2720 may be within a certain number of degrees of the outlet temperature of the compressed gas exiting the third reversible heat exchanger 2635 c at gas outlet point 2715. To accomplish this, it may be desirable to operate the system such that the gas entering the third reversible heat exchanger 2635 c at gas inlet point 2714 from the accumulator 12 may have a particular set of operating parameters. For example, the gas at inlet point 2714 may have a temperature of between about 15-40° C., or preferably between about 17.5-35° C., or more preferably between about 20-30° C. In certain preferred embodiments gas inlet point 2714 may have a pressure of around 35 - 75 bar and is approximately equal to the storage pressure of the accumulator 12. Similarly, the thermal storage liquid entering the third reversible heat exchanger 2635 c at liquid inlet point 2720 may have a particular set of operating parameters. For example, the thermal storage liquid at inlet point 2720 may have a temperature of between about 180-250° C., or preferably between about 185-225° C., or more preferably between about 190-210° C. The thermal storage liquid at inlet point 2720 may have a pressure which is almost equal to the storage pressure in thermal storage reservoir 2610 and may be between about 1345-1395 kPa, or preferably between about 1355-1385 kPA, or more preferably between about 1365-1375 kPA.

With these optimal operating parameters in mind, the third reversible heat exchanger 2635 c may be designed so that when in discharging mode, the inlet temperature of the thermal storage liquid entering third reversible heat exchanger 2635 c at liquid inlet point 2720 may be within about 25 degrees of the outlet temperature of the compressed gas exiting the third reversible heat exchanger 2635 c at gas outlet point 2715 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 13 , if the inlet temperature of thermal storage liquid entering the third reversible heat exchanger 2635 c at liquid inlet point 2720 is 194° C., the third reversible heat exchanger 2635 c may be configured such that the outlet temperature of compressed gas exiting the third reversible heat exchanger at gas outlet point 2715 is around about 170-190° C.

After exiting the third reversible heat exchanger 2635 c, the thermal fluid may be directed to the thermal source reservoir 2606, and the compressed gas may be directed to through a third expansion stage 2116 c where the gas may be expanded to about two thirds of the ratiometric pressure difference between the accumulator pressure at atmospheric pressure (i.e. the accumulator gauge pressure to the power of ⅔). The compressed gas may then be directed into the second reversible heat exchanger 2635 b, through the gas flow path in a gas discharging flow direction (indicated by flow arrows 2820), and thermal storage liquid may directed through the liquid flow path and into the second reversible heat exchanger 2635 b in a liquid discharging flow direction (indicated by flow arrows 2830) from the thermal storage reservoir 2610 to toward the thermal source reservoir 2606 whereby thermal energy is transferred from the thermal storage liquid into the compressed gas within the second reversible heat exchanger 2635 b.

As shown in FIG. 13 , during discharging mode, the second reversible heat exchanger 2635 b may be configured such that thermal storage liquid entering the second reversible heat exchanger 2635 b at liquid inlet point 2721 may be within a certain number of degrees of the outlet temperature of the compressed gas exiting the second reversible heat exchanger 2635 b at gas outlet point 2717. To accomplish this, it may be desirable to operate the system such that the gas entering the second reversible heat exchanger 2635 b at gas inlet point 2716 from the third expansion stage 2116 c may have a particular set of operating parameters. For example, the gas at inlet point 2716 may have a temperature of between about 50-95° C., or preferably between about 60-90° C., or more preferably between about 75-85° C. The gas at inlet point 2716 may have a pressure of around 11 - 18 bar and is around two thirds of the ratiometric pressure difference between the accumulator pressure and ambient pressure (i.e. the accumulator gauge pressure to the power of ⅔). Similarly, the thermal storage liquid entering the second reversible heat exchanger 2635 b at liquid inlet point 2721 may have a particular set of operating parameters. For example, the thermal storage liquid at inlet point 2721 may have a temperature of between about 180-250° C., or preferably between about 185225° C., or more preferably between about 190-210° C. The thermal storage liquid at inlet point 2720 may have a pressure which is almost equal to the storage pressure in thermal storage reservoir 2610 and may be between about 1345-1395 kPa, or preferably between about 1355-1385 kPA, or more preferably between about 1365-1375 kPA. With these optimal operating parameters in mind, the second reversible heat exchanger 2635 b may be designed so that when in discharging mode, the inlet temperature of the thermal storage liquid entering the second reversible heat exchanger 2635 b at liquid inlet point 2721 may be within about 25 degrees of the outlet temperature of the compressed gas exiting the second reversible heat exchanger 2635 b at gas outlet point 2717 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 13 , if the inlet temperature of thermal storage liquid entering the third reversible heat exchanger 2635 cb at liquid inlet point 2721 is 194° C., the second reversible heat exchanger 2635 b may be configured such that the outlet temperature of compressed gas exiting the second reversible heat exchanger at gas outlet point 2717 is around about 180-190° C.

After exiting the second reversible heat exchanger 2635 b, the thermal fluid may be directed to the thermal source reservoir 2606, and the compressed gas may be directed to through a second expansion stage 2116 b where the gas may be expanded to about one third of the ratiometric pressure difference between the accumulator pressure at atmospheric pressure (i.e. the accumulator gauge pressure to the power of ⅓). The compressed gas may then be directed into the first reversible heat exchanger 2635 a, through the gas flow path in a gas discharging flow direction (indicated by flow arrows 2820) and thermal storage liquid may directed through the liquid flow path and into the first reversible heat exchanger 2635 a in a liquid discharging flow direction (indicated by flow arrows 2830) from the thermal storage reservoir 2610 to toward the thermal source reservoir 2606 whereby thermal energy is transferred from the thermal storage liquid into the compressed gas within the second reversible heat exchanger 2635 a.

As shown in FIG. 13 , during discharging mode, the first reversible heat exchanger 2635 a may be configured such that thermal storage liquid entering the first reversible heat exchanger 2635 a at liquid inlet point 2722 may be within a certain number of degrees of the outlet temperature of the compressed gas exiting the first reversible heat exchanger 2635 a at gas outlet point 2719. To accomplish this, it may be desirable to operate the system such that the gas entering the first reversible heat exchanger 2635 a at gas inlet point 2718 from the second expansion stage 2116 b may have a particular set of operating parameters. For example, the gas at inlet point 2718 may have a temperature of between about 50-95° C., or preferably between about 60-90° C., or more preferably between about 75-85° C. The gas at inlet point 2718 may have a pressure of between of around 2 -5 bar and is around one third of the ratiometric pressure difference between the accumulator pressure and ambient pressure (i.e. the accumulator gauge pressure to the power of ⅓). Similarly, the thermal storage liquid entering the first reversible heat exchanger 2635 a at liquid inlet point 2722 may have a particular set of operating parameters. For example, the thermal storage liquid at inlet point 2722 may have a temperature of between about 180-250° C., or preferably between about 185225° C., or more preferably between about 190-210° C. The thermal storage liquid at inlet point 2720 may have a pressure which is almost equal to the storage pressure in thermal storage reservoir 2610 and may be between about 1345-1395 kPa, or preferably between about 1355-1385 kPa, or more preferably between about 1365-1375 kPa. With these optimal operating parameters in mind, the first reversible heat exchanger 2635 a may be designed so that when in discharging mode, the inlet temperature of the thermal storage liquid entering the first reversible heat exchanger 2635 a at liquid inlet point 2722 may be within about 25 degrees of the outlet temperature of the compressed gas exiting the first reversible heat exchanger 2635 a at gas outlet point 2719 (preferably within about 10 degrees, or more preferably within about 5 degrees). For example, as shown in FIG. 13 , if the inlet temperature of thermal storage liquid entering the first reversible heat exchanger 2635 a at liquid inlet point 2722 is 194° C., the second reversible heat exchanger 2635 b may be configured such that the outlet temperature of compressed gas exiting the second reversible heat exchanger at gas outlet point 2719 is around about 180-190° C.

After exiting the first reversible heat exchanger 2635 a, the thermal fluid may be directed to the thermal source reservoir 2606, and the compressed gas may be directed through a first expansion stage 2116 a where the gas may be expanded to a pressure around about atmospheric pressure and may be released to the atmosphere.

In order to facilitate the exit of the thermal storage fluid from each reversible heat exchanger during charging mode at a temperature which is within 25 degrees (preferably within about 10 degrees, or more preferably within about 5 degrees) of the inlet compressed gas temperature of that same reversible heat exchanger, and also to facilitate the exit of compressed gas from each reversible heat exchanger during discharging mode at a temperature which is within 25 (preferably within about 10 degrees, or more preferably within about 5 degrees) degrees of the inlet thermal storage liquid temperature of that same reversible heat exchanger, each of the one or more reversible heat exchangers may incorporate several specific design elements. Each reversible heat exchanger may include a plurality of tubes and an outer flow region. In certain embodiments, the outer flow region may surround and be in contact with the plurality of tubes. For example, each reversible heat exchanger may comprise a shell and tube (preferably an E-type single pass shell and tube heat exchanger), coil wound heat exchanger, a plate-and-frame exchanger or a braised plate exchanger. In certain preferred embodiments, the one or more reversible heat exchangers may include at least one flow directing member (baffle) that may extend into the outer flow region to direct the thermal storage liquid across the plurality of tubes. In certain preferred embodiments, any one of the one or more reversible heat exchangers may be a coil wound exchanger with at least two tube bundles.

In the systems disclosed herein, the gas flow path may be directed through the plurality of tubes within the heat exchanger, while the liquid flow path may be directed through the outer flow region of the heat exchanger. Referring to FIG. 14 , when an E-type single pass shell and tube type heat exchanger 4635 is used, during charging mode, the compressed gas may be directed through the tubes 4800 of the heat exchanger 4635 in a gas charging flow direction (shown as flow arrows 4820), and the thermal storage liquid may be directed through the outer flow region 4810 of the heat exchanger 4635 in a liquid charging flow direction (shown as flow arrows 4830), where the a gas charging flow direction is opposite the liquid charging direction. Referring to FIG. 15 , when a vertically oriented coil wound heat exchanger (CWHE) 5635 is used, during charging mode, the compressed gas may be directed through the upper end of the tubes 5800 of the heat exchanger 5635 in a gas charging flow direction (shown as flow arrows 5820) and out through the bottom end of the tubes 5800, and the thermal storage liquid may be directed through the bottom of the outer flow region 5810 of the heat exchanger 4635 in a liquid charging flow direction (shown as flow arrows 5830) towards the top of the outer flow region 5810, such that the gas charging flow direction 5820 is opposite the liquid charging direction 5820.

Referring again to FIG. 15 , when a coil one heat exchanger is used, the heat exchanger may optionally be configured to have multiple bundles of tubes (3 bundles shown in FIG. 15 ). Optionally, each bundle of tubes may correspond to a different stage of compression/expansion such that multiple stages of heat exchange occur within one reversible heat exchanger unit. In doing so, a three stage compression/expansion system (as shown in FIGS. 12 - 13 ) could employ one reversible heat exchanger for all 3 stages, with the compressed air for each stage flowing through its own bundle.

By directing the compressed gas stream through the plurality of tubes and the liquid stream through the outer flow region of each reversible heat exchanger, this may allow for a low pressure drop on the air side of the heat exchanger during both charging and discharging modes. For example, during charging mode, compressed gas may enter the plurality of tubes in a gas charging flow direction at a first pressure and exit the plurality of tubes at a second pressure, where the second pressure may be at least 90% of the first pressure. By way of non-limiting example, the second pressure may be between about 10 kPA and about 80 kPA less than the first pressure, or preferably the second pressure may be between about 20 kPA and about 70 kPA less than the first pressure, the second pressure may be within about 50 kPA of the first pressure. During discharging mode, compressed gas may enter the plurality of tubes in a gas discharging flow direction at a first pressure and exit the plurality of tubes at a second pressure, where the second pressure may be at least 90% of the first pressure. By way of non-limiting example, the second pressure may be between about 10 kPA and about 80 kPA less than the first pressure, or preferably the second pressure may be between about 20 kPA and about 70 kPA less than the first pressure, the second pressure may be within about 50 kPA of the first pressure.

In certain embodiments, each heat exchanger may be configured as a single pass heat exchanger. For example, when in operating mode (either charging or discharging), compressed air may flow through each heat exchanger only once during each mode (e.g., once per charging mode and once per discharging mode).

The design and configuration of heat exchangers described herein may also allow for a close approach temperature, defined as the minimum temperature difference between the two heated fluids (i.e. compressed gas in its heated state and thermal fluid in its heated state) and the two cooled fluids (i.e. compressed gas in its cooled state and thermal fluid in its cooled state), which may reduce the heat transfer potential across each heat exchanger per unit of exchanger area. By way of non-limiting example, each reversible heat exchanger may have an approach temperature that is less than about 25° C., or preferably each reversible heat exchanger may have an approach temperature that is less than about 10° C. Additionally, it may allow the hot side and cold side of the heat exchanger to be the same during both charging and discharging operational modes. In other words, this will allow for the same reversible heat exchanger to be used for flow of compressed gas in opposite directions in the same heat exchanger during charging and discharging mode, and for flow of thermal storage liquid in opposite directions in the same heat exchanger during charging and discharging mode.

FIG. 16 provides a graphical depiction of one embodiment of a preferable temperature profile for one or more reversible heat exchangers during charging mode. FIG. 17 provides a graphical depiction of one embodiment of a preferable temperature profile for one or more reversible heat exchangers during discharging mode. Ideally, a fairly close approach temperature (i.e. less than 25° C.) is maintained along the length of the heat exchanger during both charging and discharging modes.

What has been described above has been intended to be illustrative of the invention and non-limiting and it will be understood by persons skilled in the art that other variants and modifications may be made without departing from the scope of the invention as defined in the claims appended hereto. 

1. A method of processing a stream of compressed air travelling between a gas compressor/expander subsystem and an underground accumulator in a compressed air energy storage system operable in at least a charging mode and a discharging mode using at least a first reversible heat exchanger having a first gas flow path and a first liquid flow path, the method comprising: a) directing the stream of compressed air from the gas compressor/expander subsystem toward the accumulator when in the charging mode, including directing the compressed air through the first gas flow path in a gas charging flow direction, and directing a thermal storage liquid through the first liquid flow path in a liquid charging flow direction from a thermal source reservoir toward a thermal storage reservoir whereby at least a portion of the thermal energy in the compressed air is transferred from the compressed air into the thermal storage liquid within the first reversible heat exchanger; and b) directing the stream of compressed air from the accumulator toward the gas compressor/expander subsystem when in the discharging mode, including redirecting the compressed air through the first gas flow path in a gas discharging flow direction that is opposite the gas charging flow direction and redirecting the thermal storage liquid through the first liquid flow path in a liquid discharging flow direction that is opposite the liquid charging flow direction from the thermal storage reservoir toward the thermal source reservoir whereby at least a portion of the thermal energy in the thermal storage liquid is returned into the compressed air within the first reversible heat exchanger.
 2. The method of claim 1, wherein the first gas flow path and the first liquid flow path are configured so that when in the charging mode an inlet temperature of the compressed air entering the first reversible heat exchanger is within about 5-25° C. of an outlet temperature of the thermal storage liquid exiting the first reversible heat exchanger. 3-13. (canceled)
 14. The method of claim 1, wherein the first gas flow path and the first liquid flow path are configured so that when in the charging mode the gas charging flow direction is opposite the liquid charging flow direction, and so that when in the discharging mode the gas discharging flow direction is opposite the liquid discharging flow direction. 15-18. (canceled)
 19. The method of claim 1, wherein the first reversible heat exchanger comprises at least first and second exchanger modules arranged in fluid communication in parallel with each other and step a) includes directing the flow of compressed air through the first and second exchanger modules in parallel.
 20. (canceled)
 21. The method of claim 1, wherein the first reversible heat exchanger comprises at least one of a shell-and-tube exchanger, coil wound exchanger (CWHE), plate-and-frame exchanger and braised plate exchanger.
 22. The method of claim 21, wherein the first reversible heat exchanger comprises a single tube pass, single shell pass shell-and-tube heat exchanger comprising a plurality of tubes providing a portion of the first gas flow path surrounded by a shell flow path providing a portion of the first liquid flow path, and wherein the compressed air flows through the tubes and the thermal storage liquid flows through the shell flow path.
 23. The system of any claim 1, wherein the accumulator comprises a hydrostatically compensated accumulator and further comprising: a) when in the charging mode, displacing a corresponding amount of compensation liquid from the layer of compensation liquid out of the accumulator toward a compensation liquid reservoir via a compensation liquid flow path thereby maintaining the layer of compressed air at substantially the storage pressure during the charging mode; and b) when in the discharging mode, providing a return flow of the compensation liquid into the accumulator as the compressed air is removed thereby maintaining the layer of compressed air at substantially the storage pressure during the discharging mode.
 24. A compressed air energy storage system alternately operable in at least a charging mode and a discharging mode, the system comprising: a) an accumulator comprising an underground chamber having an accumulator interior for containing compressed air at a storage pressure; b) a gas compressor/expander subsystem in fluid communication with the accumulator interior via an air flow path and configured to convey a flow of compressed air into the accumulator when in the charging mode and out of the accumulator when in the discharging mode; c) a thermal storage subsystem comprising at least a first reversible heat exchanger having a first liquid flow path forming part of a thermal liquid flow path between a thermal source reservoir and a thermal storage reservoir and a first gas flow path forming part of the air flow path between the gas compressor/expander subsystem and the accumulator; wherein the system is operable in at least: a charging mode in which gas from the gas compressor/expander subsystem is conveyed through the air flow path toward the accumulator, including conveying the compressed air through the first gas flow path in a gas charging flow direction, and directing the thermal storage liquid through the first liquid flow path in a liquid charging flow direction from the thermal source reservoir toward the thermal storage reservoir whereby thermal energy is transferred from the compressed air into the thermal storage liquid within the first reversible heat exchanger, and wherein the compressed air enters the accumulator at a storage pressure; and a discharging mode in which air exits the accumulator and is conveyed through the air flow path toward the gas compressor/expander subsystem, including conveying the compressed air through the first gas flow path in a gas discharging flow direction opposite the gas charging flow direction, and redirecting the thermal storage liquid through the first liquid flow path in a liquid discharging flow direction that is opposite the liquid charging flow direction from the thermal storage reservoir toward the thermal source reservoir whereby thermal energy is reintroduced into the compressed air from the thermal storage liquid within the first reversible heat exchanger. 25-27. (canceled)
 28. The system of claim 24, wherein during the charging mode an inlet temperature of the compressed air entering the first gas flow path is within about 5-25° C. of an outlet temperature of the thermal storage liquid exiting the first liquid flow path. 29-32. (canceled)
 33. The system of claim 24, wherein during the discharging mode an outlet temperature of the air exiting the first gas flow path is within about 5-25° C. of an inlet temperature of the thermal storage liquid entering the first liquid flow path. 34-35. (canceled)
 36. The system of claim 24, wherein the thermal storage subsystem further comprises at least a second reversible heat exchanger having a second liquid flow path forming part of a thermal liquid flow path between the thermal source reservoir and the thermal storage reservoir and a second gas flow path forming part of the air flow path between the compressor/expander subsystem and the accumulator.
 37. The system of claim 36, wherein the second liquid flow path is fluidly connected in parallel with the first liquid flow path. 38-39. (canceled)
 40. The system of claim 24, wherein the first reversible heat exchanger comprises at least one of a shell-and-tube exchanger, coil wound exchanger (CWHE), plate-and-frame exchanger and braised plate exchanger.
 41. The system of claim 40, wherein the first reversible heat exchanger comprises a single tube pass, single shell pass shell-and-tube heat exchanger comprising a plurality of tubes providing a portion of the first gas flow path surrounded by a shell flow path providing a portion of the first liquid flow path, and wherein the compressed air flows through the tubes and the thermal storage liquid flows through the shell flow path.
 42. (canceled)
 43. The system of claim 41, wherein the first reversible heat exchanger is vertically oriented, and when in the charging mode the compressed air enters at an upper end of the first reversible heat exchanger, flows in a generally downwardly direction through the first gas flow path and exits at a lower end of the first reversible heat exchanger. 44-52. (canceled)
 53. The system of claim 24, wherein the first reversible heat exchanger is configured as a counterflow heat exchanger in which the gas charging flow direction is generally opposite the liquid charging flow direction and the gas discharging flow direction is generally opposite the liquid discharging flow direction.
 54. (canceled)
 55. The system of claim 24, wherein the thermal source reservoir is configured for containing the thermal storage liquid at a low storage temperature and the thermal storage reservoir is in communication with the thermal source reservoir via the thermal liquid flow path and is configured to contain the thermal storage liquid at a high storage temperature.
 56. The system of claim 24, wherein when in the charging mode the thermal storage liquid exiting the first liquid flow path is at a temperature that is greater than a boiling temperature of the thermal storage liquid when at atmospheric pressure.
 57. (canceled)
 58. The system of claim 24, wherein the thermal storage liquid comprises at least one of water, mineral oil and synthetic oil.
 59. The system of claim 24, wherein the first reversible heat exchanger includes a first end at which the compressed air enters the first gas flow path during the charging mode and exits the first gas flow path during the discharging mode, and an opposing second end at which the compressed air exits the first gas flow path during the charging mode and enters the first gas flow path during the charging mode, and wherein the first end is at a higher temperature than the second end during both the charging and discharging modes.
 60. The system of claim 59, wherein the first end is at a higher elevation than the second end. 61-62. (canceled)
 63. The system of claim 24, wherein during the discharging mode the air exits the first gas flow path at between about 180 and 250° C.
 64. (canceled)
 65. The system of claim 24, where the compressed air energy storage system comprises an underground hydrostatically compensated accumulator configured to contain a layer of compensation liquid beneath a layer of the compressed air at the storage pressure. 66-69. (canceled)
 70. The system of claim 21, where the compressor/expander subsystem has at least two stages, and where there are at least two reversible heat exchangers, one for each stage of compression/expansion.
 71. The system of claim 70, where the compressed air flows alternatively through the at least two stages compressor/expander subsystem and the at least two reversible heat exchangers during the charging and discharging modes.
 72. (canceled) 